oil prices rose for a third week in a row this past week, after the Saudis announced addition production cuts and the EIA reported the first withdrawal from US crude supplies in sixteen weeks....after rising 25% to $24.74 a barrel as US oil producers curtailed production and states began to loosen restrictions on shopping & travel last week, the contract price of US light sweet crude for June delivery opened lower on Monday and slid to a 60 cent loss at $24.14 a barrel, as concern over a persistent oil supply glut and fear of a second wave of coronavirus cases combined to more than offset the bullish impact of supply cuts at some of the world's top producers...oil prices then turned positive on Tuesday and jumped more than $2 a barrel after Saudi Arabia said it would cut production by an additional 1 million barrels per day after June 1st, and held on to most of those gains to close $1.64 higher at a five week high of $25.78 a barrel, bolstered by the hope that reopening economies would help drain the crude oil glut...but oil prices opened lower again on Wednesday a fell to $24.79 a barrel after an overnight industry report indicated a larger than expected addition to US crude supplies and held on to half of that loss to close 49 cents lower at $25.29 a barrel, after Fed Chairman Powell warned of an "extended period" of weak economic growth, even as EIA data showed an unexpected weekly decline in crude supplies both nationally and at the Cushing Oklahoma storage hub....oil supply reports, including the reported dip in U.S. crude stockpiles, pushed prices higher on Thursday as they rallied to close $2.27 or 9% higher at $27.56 per barrel after the International Energy Agency forecast lower global stockpiles in the second half of 2020...U.S. crude prices then jumped another 9% on Friday to their highest level since March, as countries around the world eased the travel restrictions they had imposed to curb the spread of the coronavirus, and closed up $1.87 at $29.43 per barrel, 49 cents off their high for the day...US oil prices thus logged a 19% gain for the week and neared a two-month high as China’s industrial output rose for the first time since the coronavirus pandemic began...
natural gas prices, on the other hand, fell for a third straight week as milder weather and virus related falling demand continued to take its toll...after falling 3.5% to end last week at $1.823 per mmBTU on ongoing coronavirus demand destruction and rising supplies, the contract price of natural gas for June delivery opened higher and rose to a 6.7 cent gain on Monday before falling back to close little changed at $1.826 per mmBTU, as forecasts for milder weather and less demand over the next two weeks offset a continued slowdown in output as companies slashed spending on new wells and shut in their old ones...natural gas prices then fell almost 6% to a three-week low of $1.720 per mmBTU on Tuesday as the weather turned milder and businesses remain closed, both meaning lower demand...tanking demand for LNG drove gas prices lower again on Wednesday, as they fell 10.4 cents to a four-week low of $1.616 per mmBTU, despite expectations that oil associated gas output would slow as a collapse in oil prices prompted firms to shut oil wells and slash spending on new drilling...a lower than expected addition to underground natural gas storage then fueled a brief rally on Thursday, as the June gas contract climbed 6.5 cents to settle at $1.681 per mmBTU, but the contract price gave back 3.5 cents of that gain on Friday, as forecasts for milder weather implied larger additions to storage in the weeks going forward...June natural gas thus ended the week priced at $1.646 per mmBTU, 9.7% lower than the previous Friday's close...
the natural gas storage report from the EIA for the week ending May 8th indicated that the quantity of natural gas held in underground storage in the US rose by 103 billion cubic feet to 2,422 billion cubic feet by the end of the week, which left our gas supplies 799 billion cubic feet, or 49.2% higher than the 1,623 billion cubic feet that was in storage on May 8th of last year, and 413 billion cubic feet, or 20.6% above the five-year average of 2,009 billion cubic feet of natural gas that has been in storage as of the 8th of May in recent years....the 103 billion cubic feet that were added to US natural gas storage this week was lower than the consensus forecast for a 110 billion cubic feet increase from a survey of analysts by S&P Global Platts, but was well above the 75 billion cubic feet of natural gas that have been added to natural gas storage during the same week over the past 5 years, and also above the 100 billion cubic feet addition of natural gas to storage during the corresponding week of 2019...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending May 8th indicated that because of a large jump in the amount of oil that went missing after it was either imported or reportedly produced, our commercial supplies of stored crude oil fell for the first time in 16 weeks and for the ninth time in the past thirty-five weeks...our imports of crude oil fell by an average of 321,000 barrels per day to an average of 5,391,000 barrels per day, after rising by an average of 410,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 21,000 barrels per day to an average of 3,525,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 1,866,000 barrels of per day during the week ending May 8th, 300,000 fewer barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells fell by 300,000 barrels per day to 11,600,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 13,466,000 barrels per day during this reporting week..
meanwhile, US oil refineries reported they were processing 12,383,000 barrels of crude per day during the week ending May 8th, 594,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that 170,000 barrels of oil per day were being added to the supplies of oil stored in the US....so based on that data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 914,000 barrels per day more than what what was added to storage plus what our oil refineries reported they used during the week....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (-914,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed...however, since the media treats these figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we'll continue to report them, just as they're watched & believed as accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,336,000 barrels per day last week, now 26.1% less than the 7,217,000 barrel per day average that we were importing over the same four-week period last year....the 170,000 barrel per day addition to our total crude inventories included 276,000 barrels per day that were added to our Strategic Petroleum Reserve, which was partly offset by 106,000 barrels per day that were being withdrawn from our commercially available stocks of crude oil....this week's crude oil production was reported to be down by 300,000 barrels per day to 11,600,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was down by 300,000 barrels per day to 11,200,000 barrels per day, while a 5,000 barrel per day decrease in Alaska's oil production to 438,000 barrels per day had no impact on the rounded national total....last year's US crude oil production for the week ending May 10th was rounded to 12,100,000 barrels per day, so this reporting week's rounded oil production figure was 4.1% below that of a year ago, yet still 37.6% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 67.9% of their capacity in using 12,383,000 barrels of crude per day during the week ending May 8th, down from 70.5% of capacity during the prior week, and among the lowest refinery utilization rates of the last dozen years...hence, the 12,383,000 barrels per day of oil that were refined this week were 25.7% fewer barrels than the 16,676,000 barrels of crude that were being processed daily during the week ending May 10th, 2019, when US refineries were operating at a seasonally typical 90.5% of capacity....
even with the decrease in the amount of oil being refined, gasoline output from our refineries was quite a bit higher, increasing by 792,000 barrels per day to 7,497,000 barrels per day during the week ending May 8th, after our refineries' gasoline output had decreased by 30,000 barrels per day over the prior week....but since the recent gasoline output increases have been coming off a 22 year low in gasoline production, our gasoline output this week was still 24.4% lower than the 9,912,000 barrels of gasoline that were being produced daily over the same week of last year....on the other hand, our refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 190,000 barrels per day to 4,892,000 barrels per day, after our distillates output had increased by 100,000 barrels per day over the prior week...after this week's decrease in distillates output, our distillates' production for the week was 7.1% less than the 5,264,000 barrels of distillates per day that were being produced during the week ending May 10th, 2019....
even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 3rd time in 6 weeks and for the 11th time in 15 weeks, falling by 3,513,000 barrels to 252,894,000 barrels during the week ending May 8th, after our gasoline supplies had decreased by 3,158,000 barrels over the prior week...our gasoline supplies decreased again this week because the amount of gasoline supplied to US markets increased by 734,000 barrels per day to 7,398,000 barrels per day, even as our exports of gasoline fell by 358,000 barrels per day to a 100 month low of 174,000 barrels per day while our imports of gasoline rose by 118,000 barrels per day to 486,000 barrels per day....and even after this week's inventory decrease, our gasoline supplies were still 12.4% higher than last May 10th's gasoline inventories of 225,024,000 barrels, and roughly 9% above the five year average of our gasoline supplies for this time of the year...
with the increase in our distillates production, our supplies of distillate fuels increased for the sixth time in 17 weeks and for the 11th time in 32 weeks, rising by 3,511,000 barrels to 155,001,000 barrels during the week ending May 8th, after our distillates supplies had increased by 9,515,000 barrels over the prior week....our distillates supplies rose by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, jumped by 689,000 barrels per day to 3,818,000 barrels per day, while our exports of distillates fell by 163,000 barrels per day to 766,000 barrels per day and our imports of distillates fell by 143,000 barrels per day to 193,000 barrels per day....after this week's inventory increase, our distillate supplies at the end of the week were 23.4% above the 125,647,000 barrels of distillates that we had stored on May 10th, 2019, and about 16% above the five year average of distillates stocks for this time of the year...
finally, with lower oil imports and the drop in our crude production, our commercial supplies of crude oil in storage fell for the first time in sixteen weeks and for the nineteenth time in the past 52 weeks, decreasing by 745,000 barrels, from 532,221,000 barrels on May 1st to 531,476,000 barrels on May 8th...but since that was after 15 straight increases and three record increases over past 6 weeks, our crude oil inventories are still 11% above the five-year average of crude oil supplies for this time of year, and almost 49% above the prior 5 year (2010 - 2014) average of crude oil stocks as of the 8th of May, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first rose above 400 million barrels, and continued rising from there....since our crude oil inventories have generally been rising over the past year and a half, except for during this past summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of May 8th were 12.6% above the 472,035,000 barrels of oil we had in commercial storage on May 10th of 2019, 22.9% above the 432,354,000 barrels of oil that we had in storage on May 11th of 2018, and 2.1% above the 520,772,000 barrels of oil we had in commercial storage on May 12th of 2017...
OPEC's Monthly Oil Market Report
Wednesday of this past week saw the release of OPEC's May Oil Market Report, which covers OPEC & global oil data for April, and hence it gives us a picture of the global oil supply & demand situation during the period when the Saudis and their allies were engaged in an oil price war against the Russians and US shale, but before before the mid-April agreement to cut production by 9.7 million barrels a day during May & June kicked in....but before we start, we should caution that estimating oil demand while most countries on the planet are engaged in varying degrees of lockdown is pretty much a crapshoot, and hence the numbers we'll be reporting this month should be considered as having a much larger margin of error than we'd normally expect from this report..
the first table from this monthly report that we'll review is from the page numbered 46 of that report (pdf page 56), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate...for all their official production measurements, OPEC uses an average of estimates from six "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thus avert any potential disputes that could arise if each member reported their own figures...
as we can see from the above table of oil production data, OPEC's oil output jumped by 1,798,000 barrels per day to 30,412,000 barrels per day in April, from their revised March production total of 28,614,000 barrels per day...however that March output figure was originally reported as 28,612,000 barrels per day, which means that OPEC's March production was revised 2,000 barrels per day higher with this report, and hence April's production was, in effect, a 1,800,000 barrel per day increase from the previously reported OPEC production figures (for your reference, here is the table of the official March OPEC output figures as reported a month ago, before this month's revisions)...
from the above table, we can also see that increases of 1,553,000 barrels per day from the Saudis, 332,000 barrels per day from the Emirates, and 259,000 barrels per day from Kuwait were the reason for the output increase in April, as every other major OPEC producer continued to adhere to the output allocations that were originally determined for each OPEC member after their December 7th, 2018 meeting, when OPEC agreed to cut 800,000 barrels per day as part of a 1.2 million barrel per day cut agreed to with Russia and other oil producers and the additional production cuts of 500,000 barrels per day through to March 2020 that were announced at their December 6th, 2019 meeting..
the next graphic from the report that we'll include shows us both OPEC and world oil production monthly on the same graph, over the period from May 2018 to April 2020, and it comes from page 47 (pdf page 57) of the May OPEC Monthly Oil Market Report....on this graph, the cerulean blue bars represent OPEC oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale...
even with the 1,798,000 barrel per day jump in OPEC's production from what they produced a month ago, OPEC's preliminary estimate indicates that total global oil production decreased by a rounded 0.18 million barrels per day to average 99.46 million barrels per day in April, a reported decrease which apparently came after April 's total global output figure was revised lower by 220,000 barrels per day from the 99.86 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production fell by a rounded 1,980,000 barrels per day in April after that revision, with lower oil production from the US, Canada, Ecuador, Brazil and Kazakhstan the major reasons for the non-OPEC output decrease in April...even with the decrease in April's global output, the 99.46 million barrels of oil per day produced globally in April were still 1.24 million barrels per day, or 1.3% greater than the revised 98.22 million barrels of oil per day that were being produced globally in April a year ago, the 4th month of OPECs first round of production cuts (see the May 2019 OPEC report (online pdf) for the originally reported April 2019 details)...with this month's big increase in OPEC's output, their April oil production of 30,412,000 barrels per day rose to 30.6% of what was produced globally during the month, up from the 28.7% share OPEC contributed in March, and the 28.1% global share they had in February...OPEC's April 2019 production, which included 528,000 barrels per day from former member Ecuador, was reported at 30,031,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 909,000 more barrels per day of oil in April than what they produced a year ago, when they accounted for 30.4% of global output, with a 1,740,000 barrel per day increase in output from Saudi Arabia, a 779,000 barrel per day increase in the output from the Emirates, and a 435,000 barrel per day increase in the output from Kuwait from that time more than offsetting a 1,094,000 barrel per day drop in the output from Libya and a 585,000 barrel per day drop in the output from Iran, to thus result in the year over year increase...
with the big jump in OPEC's output that we've seen in this report, there was a record surplus in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us...
the above table came from page 25 of the May OPEC Monthly Oil Market Report (pdf page 35), and it shows regional and total oil demand estimates in millions of barrels per day for 2019 in the first column, and OPEC's estimate of oil demand by region and globally quarterly over 2020 over the rest of the table...on the "Total world" line in the third column, we've circled in blue the figure that's relevant for April, which is their estimate of global oil demand during the second quarter of 2020...
OPEC is estimating that during the 2nd quarter of this year, all oil consuming regions of the globe will be using an average of 81.30 million barrels of oil per day, which is a 5.40 million barrel per day downward revision from the 86.70 million barrels of oil per day they were estimating for the 2nd quarter a month ago (circled in green), largely reflecting coronavirus related demand destruction....meanwhile, as OPEC showed us in the oil supply section of this report and the summary supply graph above, OPEC and the rest of the world's oil producers were still producing 99.46 million barrels per day during April, which would imply that there was a surplus of around 18,160,000 barrels per day in global oil production in April, 22.3% greater than the demand estimated for the month...
in addition to the April surplus, the downward revision of 180,000 barrels per day to March's global output that's implied in this report, combined with the 530,000 barrels per day downward revision to 1st quarter demand that we've circled in green means that the 17,718,000 barrels per day global oil output surplus we had figured for March would now be revised to a surplus of 18,068,000 barrels per day....the 530,000 barrels per day downward revision to 1st quarter demand means we'd also have to revise our February surplus oil production estimate from 1,660,000 barrels per day to 2,190,000 barrels per day, and revise our January surplus oil production estimate from 690,000 barrels per day to 1,220,000 barrels per day...
as you'll recall, OPEC, the Russians, and other oil producers have recently agreed to cut their production by 9.7 million barrels a day during May & June, in an agreement which would produce the specific reduction in output shown in the table below...a month ago, we looked at those cuts on a country by country basis, and found that because OPEC is using October 2018 as a basis for their cuts, the actual reduction from February's already depressed production level was just 5.8%, not the 23% cuts advertised...we then went out on a limb and estimated that 2nd quarter global production would still be 6,160,000 barrels per day greater than demand even after these much ballyhooed production cuts...without any recomputation of the figures that went into that estimate, the 5.40 million barrel per day downward revision to 2nd quarter demand shown above would now mean that our revised estimate for the second quarter's global oil surplus would be at 11,560,000 barrels per day...
Note: the above table was taken from an article at Zero Hedge, and it shows the oil production baseline in thousands of barrel per day off of which each of the oil producers will cut from in the first column, a number which is based on each of the producer's October 2018 output, ie., a date before the past year's and past quarter's output cuts took effect; the second column shows how much each participant will cut in thousands of barrel per day, which is 23% of the October 2018 baseline for all participants except for Mexico, while the last column shows the production level each participant has agreed to after that 23% cut...
This Week's Rig Count
the US rig count fell for the 10th week in a row during the week ending May 15th, and is now down by 57.3% over that ten week period....Baker Hughes reported that the total count of rotary rigs running in the US decreased by 35 rigs to 339 rigs this past week, which was the fewest rigs deployed in Baker Hughes records going back to 1940, down by 648 rigs from the 987 rigs that were in use as of the May 17th report of 2019, and 1,590 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business....
the number of rigs drilling for oil decreased by 34 rigs to 258 oil rigs this week, after falling by 33 oil rigs the prior week, leaving oil rig activity at its lowest since July 17, 2009, which was also 544 fewer oil rigs than were running a year ago, and less than a sixth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by 1 to 79 natural gas rigs, the fewest natural gas rigs active in 80 years of Baker Hughes records, down by 106 natural gas rigs from the 185 natural gas rigs that were drilling a year ago, and less than a twentieth of modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, two rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, and one in Lake County, California... a year ago, there were no such "miscellaneous" rigs deployed..
the Gulf of Mexico rig count was down by three rig to 12 rigs this week, the least Gulf rig activity since September 2nd 2016, with all of those Gulf rigs drilling for oil in Louisiana's offshore waters...that's ten fewer rigs than the rig count in the Gulf a year ago, when 20 rigs were drilling offshore from Louisiana and two rigs were operating in Texas waters...there are no rigs operating offshore elsewhere at this time, nor were there a year ago, so the Gulf rig count is equivalent to the national rig count, just as it has been since the onset of this past winter...
the count of active horizontal drilling rigs decreased by 31 rigs to 307 horizontal rigs this week, which was the fewest horizontal rigs active since August 18, 2006, and hence is 3 months short of a 14 year low for horizontal drilling...it was also 559 fewer horizontal rigs than the 866 horizontal rigs that were in use in the US on May 17th of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the directional rig count decreased by 5 to leave 22 directional rigs running this week, and those were down by 51 from the 73 directional rigs that were operating during the same week of last year....on the other hand, the vertical rig count was up by 1 to 10 vertical rigs this week, but those were still down by 38 from the 48 vertical rigs that were in use on May 17th of 2019....
the details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of May 15th, the second column shows the change in the number of working rigs between last week's count (May 8th) and this week's (May 15th) count, the third column shows last week's May 8th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 17th of May, 2019...
as you can see, this weeks basin totals show a decrease of 31 rigs, equal to the number of horizontal rigs removed nationally this week, which strongly suggests that all of this week's horizontal drilling changes took place in the major shale basins...checking the rig losses in the Texas part of Permian basin, we find that 15 rigs were pulled out of Texas Oil District 8, or the core Permian Delaware, and 3 more rigs were removed from Texas Oil District 7C, or the southern Permian Midland, and another rig was removed from Texas Oil District 8A, or the northern Permian Midland, and hence the Permian in Texas saw a total reduction of 19 rigs...since the overall Permian rig total was down by 23 rigs, that means that the 4 rigs that were pulled out in New Mexico must have been drilling in the western Permian Delaware, to account for the national Permian reduction of 23 rigs...elsewhere in Texas, two rigs were pulled out of Texas Oil District 1, one rig was pulled from Texas Oil District 2, and one rig was pulled out of Texas Oil District 3, any three of which could account for the 3 rig reduction in Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and thus touches on 4 Oil Districts...in other states, the three rigs that were pulled out of Louisiana were those that had been drilling in the Gulf of Mexico, the four rigs that were pulled out of North Dakota had all been drilling in the Williston basin, home of the Bakken shale, and the rig removed from the Ardmore Woodford accounts for the rig pulled out of Oklahoma...Oklahoma had another change, though, because an oil rig that was pulled out of the Granite Wash basin was offset by a natural gas rig that started up in that basin during the same period....natural gas rigs were still down by one nationally, however, because 2 natural gas rigs were concurrently removed from "other" basins not tracked separately by Baker Hughes in this report..
Shale pioneer Chesapeake considers bankruptcy filing after oil rout - (Reuters) - Chesapeake Energy Corp said on Monday it was unable to access financing and was considering a bankruptcy court restructuring of its over $9 billion debt if oil prices don’t recover from the sharp fall caused by the COVID-19 pandemic. The announcement follows last month’s statement by the pioneering shale gas producer that it was in talks to line up bankruptcy financing and was in talks for a loan to run its operations through the court proceedings. Company filings showed it had a combined debt of more than $1 billion by way of debt maturities and interest expenses, of which $250 million in senior notes were due this year. This is the second going concern warning by the Oklahoma City-based company since November. It said this quarter's review of the value of its untapped oil and gas reserves is likely to show a decline due to its distressed finances, reducing its ability to borrow against those assets. Chesapeake last week said it would prepay $25 million in incentives to top executives. Peers Whiting Petroleum Corp and Diamond Offshore Drilling Inc also gave cash awards to senior management just days before filing for Chapter 11 protection last month. The company said its net loss available to shareholders widened to $8.3 billion, or $852.97 per share, from $44 million, or $6.37, due to $8.5 billion of asset impairments. A bankruptcy filing would cap a long reversal of fortunes for Chesapeake, a company that helped revolutionize the energy industry through the relentless extraction of untapped oil and natural gas from shale rock formations, an environmentally controversial method that became known as fracking. The company was trying to pivot from natural gas to a greater emphasis on oil when a Saudi-Russian energy price war earlier this year upended its plans and the wider crude market. It was dealt another blow by the coronavirus outbreak, which caused energy demand to dwindle by shutting large swaths of the global economy. Chesapeake, which had about 2,300 employees at the end of 2019, said it laid off about 13% of its workforce in April. Last quarter, it terminated contracts of majority of the employees who joined through its $4 billion acquisition of Texas oil producer WildHorse in 2018. Chesapeake also enacted an anti-takeover plan last month to prevent a hostile buyer from acquiring the company to grab its tax-losses that can be used to deduct from future profits. The company said it had shut-in wells and delayed production of commercial quantities for sales in some areas, all of which will reduce its projected oil output by about 50% and 37% in May and June.M
Gulfport Energy takes half-billion write-down and loss on first quarter results - Gulfport Energy Corp. lost more than a half-billion dollars the first quarter of 2020, it announced this week. It reported it lost about $517.6 million, or $3.24 per share, on revenues of about $246.9 million. During the first quarter of 2019, it had earned a net income of about $62.2 million, or 38 cents per share, on revenues of about $320.6 million. A major influence on its 2020 first-quarter results was a non-cash impairment of about $553.3 million it took on its oil and natural gas properties. David M. Wood, the company’s CEO, said Gulfport remains focused on increasing efficiencies and reducing costs, following a plan it unveiled in February that heavily weights the execution of its capital expenditures program during the first half of this year. The company reported it is running one rig in its Utica Shale field, intending to keep it on through October, and one rig in the SCOOP play of the Anadarko Basin that it will keep running through the end of the year. The company stated it intends to shut-in a number of vertical wells it has drilled in the SCOOP play, impacting its production by less than 20 million cubic feet (equivalent) daily, and that other wells it participates in as a nonoperator might also be taken offline because of low commodity prices. “We remain committed to exercising capital discipline, maximizing cash flow generation, reducing costs and ensuring strong liquidity through the remainder of 2020,” Wood stated.
Shell says it will reintroduce 300 construction workers a week in ramp up at cracker site - The petrochemical plant in Beaver County is buzzing back to life with 800 workers on site as of last week and a plan to add 300 more workers per week going forward, officials at Shell Chemical Appalachia said. At the same time, Beaver County remains in the red phase of Gov. Tom Wolf’s plan to reopen businesses in the state — it is the only county in southwestern Pennsylvania that isn’t being moved to yellow this Friday. Shell, which had more than 8,000 people at the Potter construction site before the COVID-19 pandemic hit, said it would ramp up activity with precautions, such as temperature screenings, social distancing in lunchrooms and on shuttle buses, and face masks. “We will continue to conduct weekly reviews of our health and safety processes to ensure workers are safe, and that we remain in compliance with all CDC and health department guidelines,” the company said. Shell is building an ethane cracker, a natural gas power plant and several other processing facilities on the massive site where natural gas liquids extracted from shale wells will be turned into plastic pellets. The company had curtailed its workforce a few days before Gov. Wolf ordered nonessential businesses to shut down in mid-March. Throughout this period, several hundred workers still reported to work at the site for repair and maintenance duties and for cleaning and disinfecting. Before it shut down construction, Shell faced criticism for crowded shuttle buses and common areas on site. With a few hundred people coming back to work, the employees were able to park onsite, but with the expanding workforce, Shell said shuttle buses will be required again, albeit for a short distance. The company released a diagram of how passengers will be seated — one window seat in every other row will be used and masks will be required. Shell said in a statement that its safety protocols have proved effective at keeping COVID-19 from spreading and the 300-per-week worker increase will depend on it staying that way. Beaver County has confirmed 509 cases of COVID-19 and 78 deaths, nearly all at the Brighton Wellness and Rehabilitation Center. Local officials, such as the county’s district attorney, David Lozier, argued Beaver County doesn’t deserve to be left in the red zone and promised not to prosecute businesses that open.
Study finds methane leaks in PA are much higher than state reports - Pennsylvania’s prolific natural gas industry has made the state the No. 2-producing gas state in the country, second only to Texas. But the industry also releases a lot of methane, a potent greenhouse gas responsible for around 25 percent of global warming, a new analysis by a group of scientists working with the Environmental Defense Fund has found. The analysis found Pennsylvania’s shale gas industry leaked seven times more methane in 2017 than state reporting for the year indicates. It also found the conventional natural gas industry leaks an even larger amount of methane, despite producing a mere 2 percent of the state’s gas. The analysis comes as the state is creating methane rules for thousands of existing wells. DEP will begin taking comments on the rule later this month. All told, the EDF analysis found oil and gas industry leaks 16 times more methane than state figures show, though more than half of that came from shallow, or conventional, gas producers who aren’t required to report their methane emissions to the state. A spokesman for the Pennsylvania Independent Oil and Gas Association, which represents conventional oil and gas companies in the state, said the group had not yet reviewed the report and couldn’t comment on it. “The association will be commenting on DEP’s upcoming rulemaking on behalf of its members,” spokesman Dave Mashek said in an email. Dave Spigelmyer, president of the Marcellus Shale Coalition, said in a statement that the industry is improving its methods at making sure methane — a potent climate warming agent and the main component of natural gas — stays inside pipelines. “Through new technologies and best practices — such as robust leak detection and repair programs and vapor recovery systems — operators continue to make significant progress to ensure natural gas reaches market,” Spigelmyer said. The analysis follows a similar analysis of Pennsylvania emissions the group conducted two years ago. The latest study found twice the amount of gas leaking out of production in the state — over 1 million tons, or 57 billion cubic feet, which is around 1 percent of the gas produced in the state.
Even after pipeline pollution, DEQ is still resisting water protections and public participation - In March, the Virginia Department of Environmental Quality announced a new stakeholder advisory group to discuss numeric criteria for turbidity in streams. Turbidity is a measure of sediment (dirt) and organic materials that make waterbodies cloudy or muddy, harm fish and other critters and impair human uses. Numeric criteria are an important tool in permitting and enforcement. The need for these requirements is all too plain, after assaults on our waters by Mountain Valley Pipeline and DEQ’s weak responses. There are two major problems with DEQ’s effort. First, DEQ has decided to exclude willing and able members of the public from meaningful roles and has stacked the SAG with representatives of regulated industries and others with financial interests and histories of opposing stringent regulations. Sadly, this fits a pattern set by DEQ leaders. The public provides scientific and legal information and local knowledge and, in many instances, the department cursorily dismisses or ignores the contributions. Second, DEQ started this process after decades of failing to provide this most basic protection and, only then, under orders from the State Water Control Board. This lack of initiative by DEQ leaders leaves Virginia trailing behind a majority of states and our waters unprotected against severe damages that should have been stopped years ago. And this DEQ failure is not limited to turbidity. Our water quality standards and DEQ’s implementation procedures need a major reform. Agency officials won’t do it on their own. It’s time for the people of Virginia to insist on these changes. In state reviews for the Mountain Valley and Atlantic Coast pipelines, many of us warned that dirt washing off the land and released during digging and blasting through streams would produce harmful sediment pollution. MVP’s degradation of our waters has proven us right.DEQ failed to use available tools or develop necessary ones to prevent that damage in this case and these failures have allowed pollution problems in many other cases as well, though usually with much less public exposure. We’ve known that sediment was a primary source of water impairments for many decades, long before the 1972 Clean Water Act was enacted. Thousands of miles of streams and countless lakes, as well as the Chesapeake Bay, sustain severe damage from sediment discharges every year. Virginia regulators have been obligated to adopt regulations to control these pollutants since the act was adopted. Still, we could soon reach the 50th anniversary of Virginia’s inaction on this issue, unless we act soon. That would be a disgrace for a people so fervently committed to the “common wealth.”
Pa. Supreme Court preserves 'rule of capture' for fracking - A century-old legal principle that allows drillers to drain oil and gas from neighboring properties without paying for it still applies in the modern era of fracking, the Pennsylvania Supreme Court ruled on Wednesday.The high court overturned a 2018 decision by the lower Superior Court that had said the “rule of capture” does not cover companies when they use fracking to free gas from surrounding rocks underground.Under the rule of capture, oil and gas in deep reservoirs belongs to whoever pulls it from a well on his own property first — even if some of it flowed out from under a neighbor’s land. It has been applied since at least 1889 in Pennsylvania and throughout the United States.The decision to overturn the lower court’s order is a relief to the oil and gas industry, which said in court briefs that without the rule of capture it would be subject to a welter of trespass lawsuits that could cripple shale gas development in Pennsylvania.But the Supreme Court left open the idea that a company could still be subject to claims of trespassing if its fracturing operations physically cross a property boundary without permission.The Supreme Court said the Superior Court was wrong to claim that fracking is somehow different from past oil and gas extraction technologies so that the rule of capture no longer applies. The high court also said it would be wrong to assume that if gas is drained from a neighboring property by fracking that must mean man-made fractures physically trespassed over the boundary. Gas can be drained through existing cracks, the majority wrote, or move from a place of high pressure to low pressure when fracking occurs nearby.
Federal Court Excludes Evidence Of Stigma Damages In Eminent Domain Case Involving Gas Pipeline - A recurring theme in the area of eminent domain is so-called “stigma damages” caused by the construction of an improvement that may be thought to reduce the market value of a property. A common example is gas pipelines, which are sometimes associated with negative health implications in the form of explosions or environmental contamination from pipeline ruptures. In a recent decision, the U.S. Court of Appeals for the Third Circuit excluded appraisal testimony seeking to increase a damages award due to the stigma allegedly associated with the construction of a gas pipeline, finding that the methodology underlying that testimony was unreliable. UGI Sunbury LLC v. A Permanent Easement for 1.7575 Acres, 949 F.3d 825 (3d Cir.2020) involved the standard for admissibility of expert valuation testimony in a condemnation proceeding under the Natural Gas Act, 15 U.S.C. § 717 et seq. In that case, the condemnor proposed to construct an underground gas pipeline in Pennsylvania that would cross the properties at issue. The property owners engaged an appraiser who relied on a “damaged goods” theory in reaching his opinion of the compensation due to the property owners for the taking. In supporting this theory, the appraiser relied on his own experience, as well as the reduction of real estate values caused by the Three Mile Island nuclear incident in 1979, the Exxon Valdez Alaskan oil spill in 1989, and various leaking underground storage tanks. The District Court, in a non-jury trial, permitted the appraiser to testify regarding his “damaged goods” theory and attributed some weight to it in reaching its decision regarding the compensation owed to the property owners. On appeal, the Third Circuit reversed on the basis of Federal Rule of Evidence 702 and Daubert v. Merrell Dow Pharmaceuticals, Inc., 509 U.S. 579, 113 S.Ct. 2786 (1993), which provide that expert testimony is only admissible if it is based on reliable scientific methods. As the Third Circuit explained, this reliability threshold involves many factors including, among others, whether the method consists of a testable hypothesis, whether it has been subjected to peer review, the known or potential rate of error, the existence and maintenance of standards controlling the method’s operation, and whether the method is generally accepted. In rejecting the “damaged goods” theory, the Third Circuit found it had not been subjected to peer review, there was no data on the known or potential rate of error, there were no standards controlling its application, and it does not enjoy general acceptance. The Court further found that the theory was based on the appraiser’s subjective views and was inherently speculative, as the appraiser conceded in his testimony. On these bases, the Court found the “damaged goods” theory unreliable. The Court further found that the “damaged goods” theory did not “fit” the case, which is also required for admissibility, because it was not based on any examples of properties whose value actually decreased after the construction of a gas pipeline.
Could plugging orphan wells keep the suffering oil industry afloat? - Proposals to fund plugging of abandoned old oil and gas wells are gaining support across the U.S. as a way to restore jobs for oil workers displaced during the pandemic-driven price crash.The concept is being promoted by state regulators, industry trade groups and environmental organizations as a way to sustain employment while cleaning up a longstanding environmental problem that has been drastically underfunded.Across the country, states have identified more than 55,000 ownerless wells left unplugged during past waves of oil and gas drilling. Estimates of existing but unidentified wells swelled to 750,000 or more nationwide. Pennsylvania alone has 8,500 verified orphan and abandoned wells, plus an estimated 200,000 that have not been identified.The decaying wells can leak oil and gas into water, soil and sometimes nearby homes, creating an explosion hazard. Collectively, they are a significant source of climate-warming methane emissions.In recent weeks, the idea of paying oil workers to plug wells has been endorsed by energy regulators in North Dakota and Oklahoma; the environmental groups Greenpeace and Earthworks; the Natural Resources Committee in the Democratic-controlled U.S. House; and the Interstate Oil and Gas Compact Commission, a consortium of 31 oil and gas-producing states, including Pennsylvania.“We know we need to plug these wells, we know that plugging the wells provides environmental benefits, and at the same time we know that there are lots and lots of oil and gas workers, and lots and lots of equipment owned by oil and gas companies, that are sitting idle,” said Daniel Raimi, a researcher with the think tank Resources for the Future.States have existing, but underfunded, regulatory programs set up to plug orphan wells, he said, “which means that the money could flow relatively quickly and you could get people to work relatively quickly.”
Diversified to acquire 900 Appalachian wells from EQT – Alabama-based Diversified Gas & Oil PLC is purchasing 900 wells in West Virginia and Pennsylvania from gas giant EQT for $125 million, Kallanish Energy reports. The assets being purchased include 67 horizontal wells in western Pennsylvania and mostly shallow wells in West Virginia. In 2019, those assets produced net production of 9,000 barrels of oil equivalent per day, all in natural gas. Diversified is also acquiring 6,100 net conventional wells in Tennessee, Kentucky and West Virginia, 4,700 miles of intrastate gathering pipeline and two natural gas storage fields with capacity for 3.5 billion cubic feet of natural gas. Those assets are being acquired from Carbon Energy Corp. in a deal that had been announced last month. The deal is for $100 million. The price being paid by Diversified may increase if commodity prices rise. It will seek to raise $87 million through a placing of up to 64.3 million shares on the London market. It will raise $160 million to $165 million in a long-term amortising senior secured term loan with a 10-year maturity and a 6.50% coupon.
Federal judge upholds ban on process for permitting pipelines, including Mountain Valley - A federal judge has declined to lift his temporary ban on a permitting process for the crossing of streams and wetlands by oil and natural gas pipelines, including the Mountain Valley Pipeline. In an order late Monday, Montana U.S. District Court Judge Brian Morris denied the Justice Department’s request for a stay pending an appeal of the case. Morris earlier struck down a streamlined method used by the U.S. Army Corps of Engineers to approve waterbody crossings, ruling that the agency did not properly evaluate the potential harm to endangered species by the Keystone XL pipeline, which will transport crude oil from Canada to Nebraska. The sweeping ruling prevented other planned pipelines from obtaining a similar permit from the Army Corps until “completion of the consultation process and compliance with all environmental statutes and regulations” — a process expected to take months. Government lawyers had asked Morris to limit his ruling to the Keystone pipeline. But in a 38-page opinion, Morris wrote that pipeline developers “possess no inherent right to maximize revenues by using a cheaper, quicker permitting process, particularly when their preferred process does not comply with the ESA [Endangered Species Act.]” Environmentalists have argued for years that the Army Corps’ process, called a Nationwide Permit 12, takes a “blanket approach” that does not adequately assess a pipeline’s crossing of each stream or wetland in its path. “Constructing pipelines through rivers, streams and wetlands without analyzing the impacts on imperiled species is unconscionable, and we will continue to fight to protect vulnerable species, our waters and the climate from such reckless development,” Jared Margolis, a senior attorney with the Center for Biological Diversity, said in a statement. A spokeswoman for Mountain Valley wrote in an email Tuesday that “we will continue to evaluate the potential impacts to the MVP project as new information becomes available.” Natalie Cox added that work on the 303-mile pipeline — currently stalled by Morris’ ruling and other legal challenges filed by environmental groups — is still expected to be completed by the end of the year. But Mountain Valley, a joint venture of five energy companies that includes a subsidiary of RGC Resources of Roanoke, is already behind on its earlier goal to get permits restored in time to restart construction in late April. Cox’s email states that work could resume in July, assuming that Mountain Valley regains a biological opinion — the process used by the U.S. Fish and Wildlife Service to evaluate a project’s impact on endangered species — and the Federal Energy Regulatory Commission lifts its stop-work order.
EQM sees U.S. Mountain Valley natgas pipe on in 2020, analysts not so sure - (Reuters) - EQM Midstream Partners LP said on Thursday it still sees a “narrow path” to complete its long-delayed $5.4 billion Mountain Valley natural gas pipeline from West Virginia to Virginia by late 2020. Analysts, however, said Mountain Valley and other pipelines would probably be delayed by a decision by a federal judge in Montana that the U.S. Army Corps of Engineers did not comply with the Endangered Species Act. EQM said in its first quarter earnings that Mountain Valley “is working through the project’s remaining legal and regulatory challenges to achieve the targeted late 2020 full in-service date.” When EQM started construction in February 2018, it estimated Mountain Valley would cost about $3.5 billion and be completed by the end of 2018. But successful legal challenges by environmental and other groups to federal permits resulted in lengthy delays and higher costs for Mountain Valley and other gas pipes under construction like Dominion Energy Inc’s $8 billion Atlantic Coast from West Virginia to North Carolina. Then, on April 15, Chief U.S. District Judge Brian Morris ruled that the Army Corps violated federal law by issuing Nationwide Permits to cross bodies of water without adequately consulting other agencies on risks to endangered species and habitat. Although that ruling was in a case involving TC Energy Corp’s long-delayed Keystone XL crude pipeline from Canada to the U.S. Midwest, the judge applied the decision to the Army Corps’s handling of the Nationwide Permit program. This week, the judge refused to limit his decision to just the Keystone case. The U.S. Justice Department then asked the U.S. Court of Appeals for the Ninth Circuit to stay the lower court’s ruling. Analysts at Height Capital Markets in Washington said they were “skeptical” the Ninth Circuit will stay the Montana Judge’s order and noted the court may not decide the case until 2021.
Does New York need a new natural gas pipeline? It’s about to decide. - Last week, more than 100 protesters tuned into a virtual rally for a milestone push in a three-year battle against the Williams Pipeline, a controversial project that would bring a new supply of natural gas into New York City and Long Island. With individual pleas, homemade signs, musical performances, and speeches from the likes of Bill McKibben, Cynthia Nixon, and New York City Comptroller Scott Stringer, the protestors tried to summon the people power of a live event to tell New York Governor Andrew Cuomo’s administration to stop the pipeline once and for all. The rally was held ahead of the May 17 deadline for the New York State Department of Environmental Conservation to rule on a key permit for the project. The pipeline would cut through northern New Jersey and then out about 23 miles into New York Harbor to connect with the existing gas system. One year ago, the agency denied the permit on the grounds that it failed to meet the state’s water quality standards. New Jersey’s environmental agency did the same. Both rejections were issued “without prejudice,” meaning Williams could reapply — which it quickly did. National Grid, a gas utility that operates in Brooklyn, Queens, and Long Island, would be the sole customer of the pipeline’s gas. As the fate of the project hangs in the balance, so do National Grid’s long-term plans — and, according to many observers, the fate of New York City and New York State’s climate goals. Both the city and state passed landmark laws last year that seek to drastically reduce carbon emissions by 2050. The city’s Climate Mobilization Act specifically aims to cut emissions from buildings — the majority of which come from natural gas heating systems. After the Williams Pipeline permits were denied last summer, National Grid began rejecting new customer applications, claiming that it would not be able to meet future demand unless the pipeline was built. Real estate developments were stalled, new restaurants were left in limbo, and homeowners finishing up repairs couldn’t get the gas turned back on. The issue came to a head in November when Governor Cuomo accused the utility of extorting New Yorkers and threatened to revoke its license. The resulting settlement required National Grid to go back to the drawing board and come up with a slate of alternatives to make sure New Yorkers aren’t left in the cold if the pipeline isn’t built.
National Grid releases new report on natural gas capacity in New York - National Grid released its Natural Gas Long-Term Capacity Supplemental Report for Downstate New York, which includes new recommendations for the state on natural gas capacity. The report follows the original Natural Gas Long-Term Capacity Report, released on Feb. 24, which outlined 10 possible long-term natural gas capacity options for the future. National Grid held six public meetings on that report to gather feedback, which informed the two new recommendations in the Supplemental Report. Those new recommendations include a non-pipeline solution and an infrastructure solution. The report assesses cost, deliverability, and reliability risks, and consists of a range of criteria, including areas of high customer feedback. “The Supplemental Report provides these two potential pathways to solve for the capacity constraint issues in Downstate New York,” National Grid U.S. President Badar Khan said. “We look forward to a continuing dialogue with New York State to ensure a solution is agreed by June 2020, so it can be implemented in time for the winter of 2021/22.” John Bruckner, National Grid’s President in New York, said the changing conditions caused by the COVID-19 pandemic was also important in making these additional recommendations. “These include a reduction in overall demand, a modest supply increase based on ongoing internal reviews, a new risk impact analysis, and updated cost numbers for all the potential solutions that factor in the cost of carbon and customer cost impact,” Bruckner said.
Residents, Advocates Speak Out Against NJ Transit Fracked Gas Power Plant Proposal - As dozens of residents delivered public comments at this morning’s NJ Transit board meeting condemning the agency’s recent actions to push for approval of a new gas fired power plant during the worst days of the pandemic, a coalition of community and environmental groups sent a letter to Governor Murphy urging him to block the proposal and replace it with a renewable energy and storage alternative. The groups point out that the timing could not be worse for a new fossil fuel project: The state is focused on the immediate COVID public health crisis, and will face years of recovery and rebuilding that must focus on climate-friendly initiatives that will reduce harmful emissions and improve local air quality. “The Coronavirus pandemic has made it impossible to ignore the direct link between public health and the dangerous levels of fossil fuel pollution in our state,” said Sam DiFalco, organizer at Food and Water Action. “A new nationwide study by Harvard University concludes that populations exposed to higher levels of particulate matter, one of the main pollutants from burning fossil fuels, are more susceptible to the deadliest impacts of COVID-19. The stay at home orders have also shown us that our air quality will drastically improve with a reduction in fossil fuel use. New Jersey residents are now breathing cleaner air because of lower emissions, and this can be a long-term reality for our state if we commit to a rapid and fair transition to clean renewable energy, and that starts by stopping new dirty energy proposals like the NJ Transit fracked gas power plant. Governor Murphy must follow the science and protect public health by directing NJ Transit to cease all work on their dirty energy proposal, and replace it with a clean energy alternative for public transit resiliency.” “It is shameful that NJ Transit is pushing their dirty fossil fuel plant in the middle of a public health emergency. Their reckless move to rubber stamp their power plant without looking at environmental impacts or alternatives will have major impacts to public health. This area has some of the worst air pollution in the country. When they say they care about the environment, they are full of hot air. We should be using better alternatives such as renewable energy,” said Jeff Tittel, Director of the New Jersey Sierra Club. “We support federal funding going to NJ Transit to keep our trains moving and its employees with jobs. However, we should not be wasting that money on a fossil fuel power plant that would add major pollution to our air. This power plant is a dirty deal for dirty power.”
Water Regulator Defends OK of Plan to Build LNG Export Terminal in South Jersey --The Delaware River Basin Commission defended its approval of a plan to build New Jersey’s first liquefied natural-gas export terminal on the Delaware River in South Jersey, saying it had allowed critics to argue against it at a quasi-judicial hearing but sees no reason to change its mind. The interstate water regulator offered a brief statement at the start of an online “adjudicatory hearing” that presented opposing arguments by the environmental group Delaware Riverkeeper Network (DRN), and the developer of the terminal, Delaware River Partners (DRP) over whether the terminal should be built. Risk of explosion DRBC Secretary Pamela Bush said the commissioners agreed last September to a request for the hearing from DRN, which argues that the terminal at Gibbstown in Gloucester County would expose local residents to the risk of explosion, as well as overwhelming the community with truck traffic and disturbing the natural environment. But she said that holding the hearing didn’t mean the commission believes its approval was incorrect. “Rather, the hearing gives DRN an opportunity to show, by a process set forth in DRBC’s rules, that the commission’s decision should be changed,” Bush said at the start of six hours of testimony on Monday, the first day of the hearing, according to a video that was released by DRBC on Tuesday. Advocates had originally expected to face each other in person in a court-like setting, but because of social-distancing requirements during the COVID-19 pandemic, each attorney participated via video from his or her home or private office. Presiding was John Kelly, a hearing officer with the Pennsylvania Department of State, who will prepare a report, based on hearing testimony and public comments, and then make recommendations to the commission — which is not required to accept his recommendations. There is no timeline set for the hearing or for Kelly to file his report and recommendations.
Killingly gas plant wastewater discharges are another reason for worry - On April 27, the DEEP gave public notice that it had granted the controversial Killingly natural gas plant permission to discharge 90,000 gallons of toxic wastewater daily, or 32,850,000 gallons annually. At that rate, Killingly could essentially fill an Olympic-sized swimming pool with polluted water every week. This wastewater will contain lead, ammonia, petroleum, phosphorous, copper and other metals. These pollutants pose a danger to Connecticut’s residents and our natural resources alike. Lead is so notorious for causing birth defects, kidney failure and impairing childhood cognitive development that it’s unnecessary to say more. Ammoniaand phosphorous discharges threaten our aquatic resources — increased levels of ammonia and phosphorous cause bacterial and algae blooms that consume oxygen and suffocate aquatic life, leading to so-called “dead zones.” Copper can lead to liver and kidney damage.The DEEP is going to allow Killingly to direct this toxic soup to the Killingly Publicly Owned Treatment Works, the municipal water treatment plant. In 2014, Killingly residents agreed to spend over $25 million to upgrade their treatment plant. The town will pay for these upgrades with an annual 11 percent increase in sewer usage bills for four years. The DEEP is allowing a privately held, polluting natural gas plant to strain a publicly funded water treatment plant (designed to treat domestic sewage) with industrial wastewater. This doesn’t even consider the threat posed by the pipeline that will transport the natural gas, which will cut through protected lands and the Quinebaug River. The DEEP’s decision underscores the disconnect between the state’s words and deeds. Even as Gov. Ned Lamont and his administration claim commitment to bringing carbon emissions from the power sector to zero by 2040, they’re allowing the development of a new fossil fuel power plant that will emit 2.2 million tons of CO2 annually for decades. Katie Dykes, the commissioner of energy and environmental protection, justified the Killingly plant by claiming natural gas to be a “bridge from coal and oil.” This is a popular, pro-natural gas talking point. Too bad it’s not true. While natural gas releases half the CO2 of coal and oil when used as an energy source, the extraction and refining of natural gas releases massive quantities of methane gas, and methane warms the planet at 80 times the rate of CO2. Atmospheric levels of methane gas began rapidly increasing in 2007, which tracks our increased reliance on natural gas. A decade-old study by scientists at Cornell University determined that shale natural gas production is worse on the climate than coal. Methane gas has an atmospheric footprint that is at least 20% greater than coal, and “perhaps more than twice as great” as coal. If natural gas is a bridge fuel, it’s a bridge to a place worse than nowhere.
Three Enbridge Pipelines Shut After Kentucky Natgas Line Fire (Reuters) - Three of Enbridge's pipelines were shut following a fire on the company's Line 10 segment of its Texas Eastern Natural Gas System, in Fleming County, Kentucky on May 4, the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA) said on Friday.The company said on Thursday there was no estimated timeline to return its Line 10 to service.The PHMSA has deployed an investigator to the site of the incident, a PHMSA spokesperson said.No injuries were reported in the fire, which occurred in a wooded area in Fleming County.That shutdown stopped gas from flowing through the damaged section of pipe from the Marcellus/Utica Shale in Pennsylvania, Ohio and West Virginia to the U.S. Gulf Coast.Before the blast about 1.2 billion cubic feet of gas was flowing through that area, according to data from Refinitiv and was now down to around zero on some days, according to data from Refinitv.Texas Eastern has three lines between its Danville and Tompkinsville compressors in Kentucky that make up its 30-inch (76-centimeter) system. They are Lines 10, 15 and 25.
Appalachian gas markets remain strong, despite continuing Texas Eastern outage - Spot gas prices in Appalachia and the US Northeast edged higher Monday, despite an ongoing outage on Texas Eastern Transmission that will likely continue pushing back on regional supply through late May. In midday cash trading, Appalachia's benchmark supply hub, Dominion South, jumped 9 cents, rising to $1.40/MMBtu. At the nearby Texas Eastern M2 location, prices climbed 10 cents to $1.37/MMBtu. At downstream locations including Texas Eastern M3, Transco Zone 6 NY and Algonquin city-gates, cash markets were up roughly 20 cents Monday as below-average temperatures stoked regional heating demand. In a critical notice Friday, Texas Eastern said it anticipates continued north-to-south flow restrictions through its Owingsville compressor station in Kentucky over the next two to three weeks as it conducts line inspections near the site of a pipeline explosion that occurred May 4. While just one of three lines that comprise its 30-inch diameter pipeline system in the area was damaged, gas transmissions on Texas Eastern have remained at zero following the explosion as the operator works with the National Transportation Safety Board and the Pipeline & Hazardous Materials Safety Administration to evaluate options for restoring at least partial capacity through the affected segment.In the days since the explosion on Texas Eastern, below-average temperatures and elevated heating demand across the Eastern Seaboard have offered an outlet for Appalachian gas production that otherwise would have likely faced downward pressure. Over the past week, Appalachian Basin producers have churned out an average 32.4 Bcf/d, with output up roughly 100 MMcf/d compared with levels in the month prior to the pipeline explosion. As producers reroute upstream supply, production receipts on Texas Eastern have fallen about 210 MMcf/d since the outage, with smaller declines on Rover Pipeline and Tennessee Gas Pipeline. A simultaneous uptick in receipts has has been reported on Columbia Gas Transmission – up about 300 MMcf/d – along with smaller increases on Rockies Express Pipeline, Nexus Gas Transmission, Equitrans and Dominion Transmission, S&P Global Platts Analytics data shows. While the Texas Eastern outage in Kentucky has lowered Appalachian gas transmission to markets in the Southeast and the Gulf Coast by an estimated 460 MMcf/d in total since the outage began, flows to neighboring markets in the US Midwest have witnessed a simultaneous and nearly equivalent jump.
U.S. natgas little changed as milder forecasts offset slowing output - (Reuters) - U.S. natural gas futures on Monday were little changed on Monday as forecasts for milder weather and less demand over the next two weeks offset a continued slowdown in output as energy firms slash spending on new drilling and shut well after crude price collapsed due to demand destruction from the coronavirus. Those oil wells also produce a lot of gas. Front-month gas futures for June delivery on the New York Mercantile Exchange rose 0.3 cents, or 0.2%, to settle at $1.826 per million British thermal units. That kept front-month at the Henry Hub benchmark in Louisiana higher than the Title Transfer Facility (TTF) in the Netherlands. Henry Hub futures were also was trading higher than TTF in July and August. Analysts said those high U.S. prices and low prices elsewhere should prompt buyers of liquefied natural gas (LNG) to keep canceling some U.S. cargoes in coming months. In April, buyers canceled about 20 U.S. LNG cargoes that were due to be shipped in June. Looking ahead, U.S. gas futures for the balance of 2020 and calendar 2021 were trading higher than the front-month on expectations demand will jump once governments loosen coronavirus travel and work restrictions. The U.S. Energy Information Administration (EIA) projected gas production will fall to an annual average of 91.7 billion cubic feet per day (bcfd) in 2020 and 87.5 bcfd in 2021 from a record 92.2 bcfd in 2019 due to the reduction in drilling. Data provider Refinitiv said average gas output in the U.S. Lower 48 states has fallen to 90.3 bcfd so far in May, down from an eight-month low of 92.9 bcfd in April and an all-time monthly high of 95.4 bcfd in November.
U.S. natgas falls near 6% as mild weather and coronavirus cut demand - Reuters- U.S. natural gas futures fell almost 6% to a three-week low on Tuesday on forecasts for demand to drop as the weather turns milder and businesses remain closed due to government lockdowns to stop the spread of coronavirus. Those price declines, however, were limited by a continued slowdown in output as a global crude glut and slumping fuel demand due to the lockdowns caused oil prices to collapse, prompting energy firms to slash spending on drilling and shut oil wells. Those oil wells also produce a lot of gas. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 10.6 cents, or 5.8%, to settle at $1.720 per million British thermal units, their lowest close since April 16. Since late April, the front-month at the Henry Hub benchmark in Louisiana has traded higher than the Title Transfer Facility (TTF) in the Netherlands. Henry Hub futures were also trading higher than TTF in July and August. Data provider Refinitiv said average gas output in the U.S. Lower 48 states has fallen to 90.3 bcfd so far in May, down from an eight-month low of 92.9 bcfd in April and an all-time monthly high of 95.4 bcfd in November. The EIA projected coronavirus lockdowns will cut U.S. gas use - not including exports - to an average of 81.7 bcfd in 2020 and 79.2 bcfd in 2021 from a record 85.0 bcfd in 2019. With the weather expected to turn milder, Refinitiv projected demand in the Lower 48 states, including exports, would fall from an average of 85.7 bcfd this week to 79.2 bcfd next week. That is lower than Refinitiv's demand forecasts on Monday of 86.4 bcfd this week and 81.6 bcfd next week. Even though the coronavirus is reducing global gas use, the EIA still expects U.S. exports to hit record highs in coming years as more LNG export plants and pipelines enter service. Still, the agency has reduced its projections on the pace of that growth due to the pandemic. Refinitiv said U.S. LNG exports have averaged 7.2 bcfd so far in May, down from a four-month low of 8.1 bcfd in April and an all-time high of 8.7 bcfd in February.
U.S. natgas futures fall to 4-week low on coronavirus demand destruction - (Reuters) - U.S. natural gas futures fell to a four-week low on Wednesday on forecasts for domestic demand and exports to drop as businesses remain closed due to government lockdowns to stop the spread of the coronavirus. That decline came despite expectations output will slow as a collapse in oil prices due to the pandemic prompted energy firms to shut oil wells and slash spending on new drilling. Those oil wells also produce a lot of gas. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 10.4 cents, or 6.0%, to settle at $1.616 per million British thermal units, their lowest close since April 15. Despite the decline, the front-month at the Henry Hub benchmark in Louisiana has traded higher than the Title Transfer Facility (TTF) in the Netherlands since late April. Henry Hub futures were also trading higher than TTF in July and August . Analysts said higher U.S. prices should prompt buyers of liquefied natural gas (LNG) to cancel more U.S. cargoes in coming months. In April, buyers canceled about 20 U.S. cargoes due to be shipped in June. Looking ahead, U.S. gas futures for the balance of 2020 and calendar 2021 were trading higher than the front-month on expectations demand will increase once governments loosen coronavirus travel and work restrictions. The U.S. Energy Information Administration projected gas production will fall to an annual average of 89.8 billion cubic feet per day (bcfd) in 2020 and 84.9 bcfd in 2021 from a record 92.2 bcfd in 2019 due to the reduction in drilling. Even though the coronavirus is reducing global gas use, the EIA still expects U.S. exports to hit record highs in coming years as more LNG export plants and pipelines enter service. Still, the agency has reduced its projections on the pace of that growth due to the pandemic. .
US working natural gas volumes in underground storage rise by 103 Bcf: EIA | S&P Global Platts -- The US Energy Information Administration reported a second consecutive triple-digit build, but production declines could affect the injection for the week in progress. Storage inventories increased by 103 Bcf to 2.422 Tcf for the week ended May 8, the US Energy Information Administration reported Thursday morning. The injection was less than S&P Global Platts' survey of analysts calling for a 110 Bcf build. Responses to the survey ranged from an injection of 89 Bcf to 118 Bcf. The injection was more than the 100 Bcf build reported during the same week last year as well as the five-year average addition of 75 Bcf. Storage volumes now stand 799 Bcf, or 49%, higher than the year-ago level of 1.623 Tcf and 413 Bcf, or 20.6%, more than the five-year average of 2.009 Tcf. Upstream, supplies were down by a combined 1.7 Bcf/d to an average 92.6 Bcf/d, mainly on a drop in onshore production, according to S&P Global Platts Analytics. The Midcontinent market showed a substantial drop in production of nearly 1 Bcf/d and was joined by smaller declines spread across several other regions as well. The rapid downturn in the balance highlights how the effect of the coronavirus pandemic on US gas markets will shift this summer from a bearish demand story to a bullish production one. June Henry Hub NYMEX rallied 8 cents following the report, helping shore-up recent declines in the balance-of-summer strip pricing, which had dipped below $2/MMBtu at Wednesday's close after only 10 days prior peaking at $2.35. Spreads to next winter have widened in the past few weeks, and the winter contract strip is now trading roughly 85 cents over the balance of summer, which may induce elevated injection activity. Platts Analytics' supply and demand model expects a 79 Bcf addition to US storage volumes for the week ending May 15. This would be 8 Bcf less than the five-year average. The week in progress has seen a re-tightening of balances as supply has held virtually flat while residential and commercial demand has rallied on colder weather across the eastern United States. Total demand has increased by an average 4.3 Bcf/d on the week as temperatures plummeted by an average 7.5 degrees across the higher-demand Midcontinent and Northeast regions, according to Platts Analytics. This has helped support a resurgence of residential and commercial demand, but the colder weather is expected to lift by this weekend, likely sending demand lower once again. Upstream, supplies have remained more or less locked-in at just below 93 Bcf/d, with all of this week's 400 MMcf/d increase stemming from an increase in net imports from Canada, to meet the stronger demand in the Midwest and Northeast.
U.S. natgas futures rise 4% on smaller than expected storage build - (Reuters) - U.S. natural gas futures rose 4% on Thursday on a smaller-than-expected storage build and a slowdown in output as energy firms shut oil wells and slashed spending on new drilling after crude prices collapsed over the past couple of months due in part to demand destruction from the coronavirus pandemic. Those oil wells also produce a lot of gas. The price increase came despite forecasts for domestic demand and exports to drop as government lockdowns to stop the spread of the virus cut gas use around the world. The U.S. Energy Information Administration said utilities injected 103 billion cubic feet of gas into storage during the week ended May 8. That is slightly less than the 107-bcf build analysts forecast in a Reuters poll and compares with an increase of 100 bcf during the same week last year and a five-year (2015-19) average build of 85 bcf for the period. The increase during the week ended May 8 boosted stockpiles to 2.422 trillion cubic feet, 20.6% above the five-year average of 2.009 tcf for this time of year. Front-month gas futures for June delivery on the New York Mercantile Exchange rose 6.5 cents, or 4.0%, to settle at $1.681 per million British thermal units. On Wednesday, the contract closed at its lowest since April 15. The 8% collapse in the Henry Hub in Louisiana briefly pushed the U.S. benchmark below the front-month Title Transfer Facility (TTF) in the Netherlands for a second day in a row on Thursday. The TTF front-month has mostly traded at a premium to Henry Hub since April 30, when it closed over the U.S. contract for the first time in a decade. Henry Hub futures, however, continued to trade over TTF in July and August . Analysts said those higher U.S. prices should prompt buyers of liquefied natural gas to continue canceling U.S. cargoes in coming months. In April, buyers canceled about 20 U.S. LNG cargoes due to be shipped in June.
U.S. natgas futures slide on forecasts for milder weather next week - (Reuters) - U.S. natural gas futures slipped on Friday on forecasts for milder weather and less demand next week despite an outlook calling for higher temperatures and more air-conditioning use in two weeks. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 3.5 cents, or 2.1%, to settle at $1.646 per million British thermal units. For the week, the contract was down about 10% after falling about 4% in the prior week. Government lockdowns to stop the spread of coronavirus have cut energy use, causing fuel prices and exports to drop as businesses shut. U.S. crude futures are down about 50% this year. U.S. producers have reacted quickly to the price collapse by shutting oil wells and slashing spending on new drilling. Those oil wells also produce a lot of gas. But now that output is dropping, prices are expected to rise in the future as governments slowly lift travel restrictions. U.S. gas for the balance of 2020 and calendar 2021 was trading much higher than the front-month. The U.S. Energy Information Administration projected gas production will fall to an annual average of 89.8 billion cubic feet per day (bcfd) in 2020 and 84.9 bcfd in 2021 from a record 92.2 bcfd in 2019. U.S. gas prices for June at the Henry Hub benchmark in Louisiana have mostly traded over the Title Transfer Facility (TTF) in the Netherlands since late April. As long as U.S. prices remain over the European benchmark - Henry Hub is also trading over TTF for July and August - analysts said LNG buyers will keep canceling U.S. cargoes. In April, buyers canceled about 20 U.S. LNG cargoes due to be shipped in June.
Energy regulator declines states' request for moratorium on pipeline approvals - Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee has rejected a request from several states to pause approvals for new energy infrastructure projects such as natural gas pipelines. Chatterjee, in a Tuesday letter to Virginia Attorney General Mark Herring (D), argued that energy projects are important to the country’s infrastructure and said a moratorium would be “short-sighted and impractical.” “As our nation grapples with these uncertain and unprecedented times, the energy sector must continue to deliver reliable and affordable energy for everyone,” he wrote. “Hindering the build-out of energy infrastructure now could have long-term and lasting negative impacts on the delivery of energy the future.” “For these reasons, I view requests for a moratorium on energy projects to be short-sighted and impractical,” the commissioner added. “Any step to slow the energy economy is a step in the wrong direction.” Last week, attorneys general from 10 states and Washington, D.C., wrote a letter saying that waiting to approve the projects is necessary in order to protect the due process rights of people who might be affected by them. “The COVID-19 pandemic has imposed even greater burdens on communities attempting to organize their interests and participate in Commission proceedings,” they wrote. “The Commission should account for the unprecedented hardships the pandemic has imposed on citizens and postpone any approvals of permanent gas infrastructure until those affected by its decisions can once again focus on these matters.” Chatterjee also addressed this argument in his letter, writing the commission continues “to post all submittals and issuances on the FERC eLibrary website and we continue to receive comments, which enable us to thoroughly consider and address parties’ concerns in our orders.” A FERC spokesperson said in an email that Chatterjee will be replying soon to all of the attorneys general who wrote to him, but responded to Herring first because of questions about specific projects. Asked for comment on Chatterjee's letter, a spokesperson for Herring said in an email that the attorney general "made a very reasonable request for FERC to hit pause on approving new fossil fuel projects that will exacerbate climate change and pollute the air while we’re in the middle of an outbreak of a deadly respiratory disease that limits the public’s ability to weigh-in." "Many of these projects directly affect the populations and communities around them and the public deserves the right to an unrestricted comment and debate period before a project is finalized in their area," the spokesperson added.
Michigan to Enbridge: Line 5 tunnel permit application is incomplete - Before Enbridge can seek a permit to build the Line 5 tunnel to transport oil and natural gas beneath the Straits of Mackinac, Michigan regulators say the company needs to spend more time considering alternatives.That’s one of several conclusions state officials reached when they reviewed Enbridge’s application for a permit from the Michigan Department of Environment, Great Lakes & Energy to build the controversial tunnel between Michigan’s two peninsulas. In a May 4 letter to the Canadian petroleum conglomerate, a state district supervisor gave Enbridge 30 days to update its application with more information.Regulators said Enbridge’s application was unnecessarily long, at more than 350 pages, but omitted key information state officials need to help decide whether to grant the permit. “EGLE requests that Enbridge edit submitted materials for precision and relevance to actual proposed construction,” wrote Joseph Haas, a supervisor in EGLE’s Gaylord District Office.In addition to submitting “a complete assessment of the alternatives” to the tunnel project, the letter stated, Enbridge must outline plans to mitigate damage the tunnel project could cause to wetlands and federally-protected plants, offer details about ongoing lawsuits that could affect the tunnel’s fate, and add other missing pieces to the application.The holdup is the latest twist in a long battle over the fate of the 67-year-old pipeline, which transports 540,000 barrels daily of crude oil and natural gas liquids between Wisconsin and Ontario. Opponents have long called for its shutdown, arguing the pipeline poses a catastrophic hazard to the Great Lakes and inland waterways. Under a 2018 agreement Enbridge reached with the administration of Gov. Rick Snyder just before the Republican left office, the company plans to replace the 4-mile section that sits exposed at the bottom of the straits with a new line encapsulated in a concrete-lined tunnel deep beneath the lakebed.Enbridge contends the tunnel plan would virtually eliminate the possibility of a spill in the Straits, but opponents cite other environmental concerns, including spill risks on inland waterways and the environmental impacts of fossil fuels, in their continued opposition to the tunnel and the larger pipeline. Snyder’s successor, Democratic Gov. Gretchen Whitmer, campaigned on a promise to shut the pipeline, but so far she and Attorney General Dana Nessel, who also opposes the pipeline, have been unsuccessful in that effort.State regulators on Wednesday said the letter to Enbridge is merely a routine step in the permitting process.“This type of back-and-forth correspondence is common for the majority of applications we review for completeness,” EGLE spokesman Scott Dean said.That didn’t stop Line 5 opponents from heralding the letter as an incremental victory in their fight against the tunnel project. “The burden is now on Enbridge to prove why Michigan and the Great Lakes should shoulder the huge risk of having Line 5 oil pipelines in the Great Lakes and crossing 400 other waterways,” said Sean McBrearty, coordinator of the anti-Line 5 group Oil & Water Don’t Mix, in a statement.
State tells Enbridge to rewrite Line 5 application - Conservation groups are praising the state for handing the Line 5 pipeline replacement project another setback.The State Department of Environment, Great Lakes and Energy has asked Enbridge to rewrite its permit application to rebuild an oil and gas pipeline underneath the Straits of Mackinac and include alternative options. David Holtz, communications coordinator for the group Oil and Water Don't Mix, says the state must consider the risk of a spill. "In the letter to Enbridge, the state made clear that it was going to apply environmental standards in evaluating the permit," he points out. "And what that means is that the agency has to determine what the impact of that pipeline will be, including on the Great Lakes but also climate change." Enbridge says its project will bring jobs and energy security to Michigan while practically eliminating the possibility of a spill in the Straits. Opponents cite other environmental concerns, including spill risks on inland waterways and the environmental impacts of fossil fuels. Enbridge spokesperson Ryan Duffy told The Bridge magazine the company plans to provide the requested information to forward with the process. Pending permit approvals, Enbridge officials hope to begin construction on the $500 million tunnel project next year and bring the new segment online in 2024.State Attorney General Dana Nessel has filed a separate suit alleging that the easement for the pipeline, granted in 1953, violates current environmental law and should be voided. Ingham County Circuit Court Judge James Jamo is scheduled to hear arguments on that complaint May 22nd.Holtz says the new Line 5 should not be built -- and wants the old pipeline decommissioned. "This pipeline doesn't belong in the Great Lakes," he stresses. "It crosses 400 other waterways. Michigan doesn't need the oil. There are other solutions to getting propane to heat homes in the UP. That's been demonstrated."
Feds launch public comment on Enbridge tunnel permit application -The U.S. Army Corps of Engineers has deemed Enbridge’s permit application for the construction of a utility tunnel beneath the Straits of Mackinac complete, a little more than a week after state environmental experts said it was not.The Army Corps set a public comment period that will last through June 4 on the application seeking permission to build a roughly 4-mile tunnel to house a new segment of the Line 5 oil pipeline. “This first determination, coming approximately one month after submittal, is significant and moves the process one step further to the tunnel becoming a reality,” Enbridge spokesman Ryan Duffy said Tuesday.The Army Corps considered the application "administratively complete" after Enbridge responded to two separate requests May 4 and May 7 for additional information, said Katie Otanez, a regulatory project manager for the corps' Detroit District. "We have not scheduled a public hearing, but commenters to the public notice may request a public hearing," Otanez said. "The corps will determine whether a public hearing is needed based on whether a hearing is likely to result in information that could not otherwise be gained." If approved for state and federal permits, the Canadian company plans to begin construction of the tunnel in 2021 and begin operating the new Line 5 within the tunnel 2024. The Whitmer administration opposes the tunnel's construction. The go ahead from the Army Corps comes roughly a week after the state said the Canadian oil company’s application was incomplete and requested further information and edits that provide more specificity on the plan. Duffy said the company is working to provide answers to the state's request for additional information, which he called a “routine request.” “Enbridge appreciates the timeliness and important feedback we are receiving from the permitting agencies,” Duffy said. Enbridge has until June 3 to respond to the May 4 request for more information, said Scott Dean a spokesman for the Michigan Department of Environment, Great Lakes and Energy. When the department decides the company's application is "administratively complete," the application will be placed on public notice for 20 days, Dean said. State and federal environmental reviews of permit applications vary because they fall under separate state and federal laws, he said.
AG Nessel Calls on MPSC to reject Enbridge's attempt to bypass review process for building new pipelines - Attorney General Dana Nessel recently urged the Michigan Public Service Commission (MPSC) to reject an attempt by Enbridge Energy Limited Partnership to bypass the normal legal process for reviewing proposals to locate and construct new oil pipelines in Michigan. "Enbridge's proposed new pipeline must be thoroughly and publicly vetted through the process required by Michigan law, including full review by the MPSC," said Nessel. "There is too much at stake to allow anything else." Enbridge submitted an application on April 17 to the MPSC under the law that governs oil pipeline siting a 1929 Public Act to approve the construction of a new pipeline in a proposed tunnel beneath the Straits of Mackinac to replace part of its Line 5. Nessel filed comment opposing Enbridge's request on Wednesday, and explained that it should be denied for several reasons:
-Enbridge's project is not, as it claims, simply "maintenance" of the pipelines approved in 1953; it proposes to locate and build a new and different pipeline.
-Act 16 and MPSC's rules plainly require an application to locate and construct a new oil pipeline.
-Enbridge's claim that a new approval is "never" required for this type of project is false; Enbridge itself has previously applied for approval to replace sections of other pipelines in Michigan.
-The MPSC has a duty to consider the potential environmental impacts of the project that cannot be bypassed through Enbridge's requested declaratory ruling.
Tribe specialty, environmental law groups join fight against Enbridge tunnel | WPBN -- An Upper Peninsula community is adding allies in its legal battle against Enbridge. On Tuesday, Bay Mills Indian Community announced Earthjustice and the Native American Rights Fund will be assisting in the legal battle against the energy company. Earthjustice is a nonprofit public interest environmental law organization working to protect people’s health, to preserve magnificent places and wildlife, to advance clean energy, and to combat climate change. NARF has provided specialized legal assistance to Indian tribes, organizations, and individuals nationwide since 1970. NARF works in such critical areas as tribal sovereignty, treaty rights, natural resource protection, voting rights, and Indian education. This comes as Enbridge continues to work on a new Line 5 tunnel under the Straits of Mackinac."We are pleased to expand our presence in the Midwest and stand with Bay Mills in defense of the Great Lakes—the largest freshwater system in the world—and the incredible and complex ecosystems that have sustained the Anishinaabe people for generations,” said Gussie Lord, director of Tribal Partnerships at Earthjustice. “Bay Mills has consistently voiced its concerns about the continued operation of Line 5 through the Straits of Mackinac and across other ceded territory in Michigan where it holds treaty-protected rights. BMIC and the new legal advocates said they intend to pursue all avenues to prevent the construction of the tunnel and the pipeline's presence in the area. Earthjustice and NARF attorneys have filed a Petition to Intervene to participate as a party in the Enbridge Line 5 Tunnel Project proceedings before the Michigan Public Service Commission. The construction of the Great Lake Tunnel Project is set to begin in 2021 with the new Line 5 segment in service by 2024. “With their application to move a section of the Line 5 pipeline to a tunnel dug under the Straits of Mackinac, Enbridge proposes a significant project that could have extreme impacts on the area’s waterways and wildlife. Over the years, the tribe has consistently fought to protect their fishing and hunting rights. Yesterday's filing continues that fight. NARF is proud to stand with the nation to ensure that the Bay Mills Community’s fishing lifeways and tribal homelands are adequately protected for generations to come,” said NARF Staff Attorney David Gover.
Illinois oil production slumps during pandemic — Oil production in Illinois has been on the decline for many years, but a steep drop in demand brought on by the economic slowdown spurred by the COVID-19 pandemic has taken a big bite out of the industry. “Our production for the first quarter was actually a little bit stronger, quarter-over-quarter, but there's no doubt that our production will decline in the second quarter,” Seth Whitehead, spokesman for the Illinois Petroleum Resources Board, said during an interview this week. “You know, just the eyeball test looking around, where I live in Fayette County, there are a lot of shut-ins at the moment. And right now, the price of oil is about $12 to $15 below where it needs to be for producers to turn a profit.” Illinois tops single-day COVID-19 test record with 20K According to the industry website oilmonster.com, Illinois crude oil was trading at $21.25 per barrel on April 3, well below the roughly $35 per barrel most producers need to turn a profit. But as most states have asked their residents to limit nonessential travel, demand for oil in the United States has plummeted, and on Thursday, May 7, Illinois crude was down to $10.50 per barrel. Although it is a relatively small part of Illinois’ overall economy, oil production remains an important industry in parts of the state, especially southeast Illinois. Whitehead said one reason it is often overlooked is because the industry is concentrated in sparsely-populated counties. Illinois judge to reject lawsuit over ballot obstacles for constitutional amendment “You know, 15 counties produce 90 percent of the oil in Illinois and 2 percent of the entire population resides in those counties,” he said. “So, it's very spread out over a very rural area.” In the early part of the 20th century, according to IPBR, oil production was a major part of the state’s economy and Illinois was the nation’s third leading oil producing state. Today, the state produces only about 9 million barrels per year, Whitehead said. Still, he said, about 4,000 jobs in Illinois are directly tied to the industry, plus another 14,000 jobs in refineries and other industries that are indirectly tied to oil production. The industry also accounts for $770 million in personal income in the state and it provides royalty income to more than 30,000 individuals. It also generates about $330 million in tax revenue for the state, plus $93.4 million in property tax revenue for local governments. Even before the pandemic hit the United States, oil prices had been falling due to overproduction in countries like Saudi Arabia and Russia and a lack of storage capacity in the United States. It remains to be seen how long it will take for prices to recover enough for the oil industry in Illinois to bounce back. But Whitehead said industry officials here remain optimistic. “We'll definitely see a short-term production decline …” he said. “But if the pandemic eases and things get back to normal sooner, rather than later, the industry has a better chance of coming out of this looking in pretty good shape. But the longer it goes on, obviously, the tougher it’ll get.”
Yet Another State Quietly Moves To Criminalize Fossil Fuel Protests Amid Coronavirus - Alabama lawmakers this week advanced legislation to add new criminal penalties to nonviolent protests against pipelines and other fossil fuel projects, setting a course to become the fourth state to enact such measures amid the chaos of the coronavirus pandemic. The bill would designate virtually any oil, gas or coal equipment or facilities in the state as “critical infrastructure” and severely prohibit where aerial drones that watchdog groups depend on to track pollution can fly. The legislation would make any action that “interrupts or interferes” with pipelines, storage depots or refineries a Class C felony, punishable with at least one year in prison and up to $15,000 in fines. Kentucky, South Dakota and West Virginia enacted similar measures in March, just as states started implementing lockdowns to contain the outbreak of COVID-19, the respiratory illness caused by the virus. The Alabama Senate passed the bill on March 12, just before state officials, alarmed at the spread of the virus, postponed legislative hearings for a month. When the capitol reopened in Montgomery on May 4, state Democrats remained in their home districts, but enough Republican lawmakers returned to restart work on the legislation. On Monday, the House version of the bill was introduced and referred to the committee that oversees utilities and infrastructure. On Thursday, lawmakers hit pause again, pledging to work instead on budgets, bond issues for school and college funding, and local bills until the next legislative session.State Sen. Cam Ward, the lead Republican championing the measure, told HuffPost the bill “will not be voted on this session due to the COVID-19 delay in our session.” But this is “a high-priority bill,” said Michael Hansen, executive director of Gasp, a clean-air advocacy group based in Birmingham. “So the moment they get a chance, they will pass it,” he said.
Gulf Coast communities grapple with oil and gas impacts - Oil and natural gas were extracted from the Permian Basin’s prolific shale deposits of southeast New Mexico and West Texas for decades. Since about 2017, the extractive industry boomed in the region — led by hydraulic fracturing and unconventional, horizontal wells able to access harder-to-reach crude oil reservoirs. Much of those resources were shipped via pipeline to the Gulf Coast, another major U.S. oil-producing region in east Texas and western Louisiana, for refining and export to the global market. Thousands of miles of pipelines were developed, to eliminate transportation bottlenecks as millions of gallons of fossil fuels were destined for travel up to 800 miles out of the Permian across Texas to the coast. The surge in production and refining had a cultural and environmental impacts on the region. The story of the Permian Basin could not be fully told without including the generations of changes to the coast, its land and people. "A robust network of oil and natural gas pipelines connect the exploration and production activity in the Permian Basin to the complex, interconnected system of storage tanks, refineries, manufacturing facilities, (liquefied natural gas) and export facilities along our Gulf Coast," said Todd Staples, president of the Texas Oil and Gas Association. Staples said the connection between the Permian and Gulf Coast was essential to the industry's ability to extract crude oil and develop a vast multitude of products from fuel that powers cars to plastic used in their construction. "The downstream sector of the oil and natural gas industry, with its large presence along the Gulf Coast, is indispensable when it comes to creating the everyday goods that make modern life possible," Staples said. Much of those resources would be sent to the Gulf Coast for export and refining, strengthening its position as a prominent region for oil and gas. The 2019 Energy Outlook from Louisiana State University reported U.S. crude production last year was up to 3.5 billion barrels, with natural gas climbing above 35 trillion cubic feet, largely fueled by the Permian and Gulf Coast.Meanwhile, the Outlook reported several pipeline projects connecting the Permian with the Gulf Coast were announced in the last two years, with a total capacity of about 3 million barrels per day to be available by 2020.
Coronavirus: Louisiana oil industry 'relief' renewed in legislation - Louisiana's oil and gas industry could succeed on some key legislative proposals that have failed in the past as leaders urge passage during the historic collapse of oil prices. The industry's push to stifle coastal lawsuits and to provide severance tax relief has made progress through the Legislature, in part boosted by arguments that the industry needs "life support" measures to stay afloat. "There's no doubt that we're facing challenging times as an industry right now," Louisiana Oil and Gas Association President Gifford Briggs said to the House Natural Resources and Environment Committee on Wednesday. "This is unlike anything we've ever seen." The association is advocating several measures for passage this session, some that have been on the industry's wish list for years, long before the COVID-19 crisis. More: Amid coronavirus, Louisiana oil and gas workforce sees 23% layoffs, wells shut, fear more Oil prices opened around $25 on Wednesday. LOGA says oil producers need the price to hit $37 to break even. As the industry hopes to avoid huge shutdowns and layoffs, leaders are pushing these measures in the Legislature. Reduce Louisiana's severance tax on oil and gas House Bill 506 status: Passed by House Committee on Ways and Means, waiting for House vote HB506, by Republican Rep. Phillip DeVillier from Eunice, would reduce the severance tax on oil, which currently sits at 12.5%. The severance tax is a state tax paid on all natural resources produced in the state, but the bulk of the collected revenue comes from oil. The oil and gas industry has long been critical of the tax, and the original intention of HB506 was to reduce the tax rate down to 8.5% by July 1, 2028. But the bill was amended to include a short-term reduction in the rate due to COVID-19. More: Gov. John Bel Edwards delays collection of severance tax to help oil and gas The bill would lower the rate from 12.5% to 2% from July 1, 2020, to June 30, 2021, when the price of oil is below $30. The bill would result in a $112.6 million loss of revenue for the next five years for the state, and the parishes, which receive a portion of the revenue, could see $6.9 million in lost revenue by Fiscal Year 2029. The fiscal note says it's difficult to measure the lost revenue — especially with the historic glut of oil on the market — but said "the bill can only result in a significant loss of state severance tax receipts and parish allocation amounts from what would otherwise be the case." The severance tax provides the state with a significant amount of revenue. The majority of the revenue goes to the state, and in fiscal year 2019, the tax brought in $529 million, according to the Louisiana Department of Revenue.
LA. Senate bill undermines parish lawsuits against oil and gas — A vote on a contentious Louisiana Senate bill that would undermine parishes’ lawsuits against oil and gas companies keeps getting delayed, in spite of a full-court press by business and industry groups to get it passed. Late Thursday, a spokeswoman for Gov. John Bel Edwards said the governor is against the bill. “Some of these coastal lawsuits were filed by the parishes years ago — many before Governor Edwards took office — under statutory authority that was expressly given to them by the Legislature decades ago,” Edwards spokeswoman Christina Stephens told WWL-TV. “The bill in question seeks to retroactively divest them from the lawsuits that are already in progress, which the Governor believes is wrong. The parishes that have chosen to file lawsuits deserve to have their day in court.” The bill, SB 359 by Sen. Bob Hensgens, R-Abbeville, would clarify the law on coastal use permits to prevent six coastal parishes —Jefferson, Plaquemines, St. Bernard, St. John the Baptist, Cameron and Vermilion – from enforcing permit violations and to give that power exclusively to the state. But those parishes already filed lawsuits against dozens of oil and gas companies back in 2013 seeking hundreds of millions of dollars. They already agreed on a settlement with one of the oil companies, Freeport McMoran, that stands to net them $100 million for coastal restoration. A coalition of business and industry groups has taken out full-page ads in newspapers urging support for SB 359, saying Louisiana should "work with the oil and gas industry, not against it." The ads claim the coastal lawsuits “drive away jobs, people and investments at a time when we need them most.” It isn’t lost on the bill’s supporters that the oil and gas industry is struggling mightily with record low crude oil prices and reduced demand during the coronavirus shutdown. If SB 359 passes the Senate and the House, opponents believe Gov. John Bel Edwards will veto it because it would take away the parishes’ rights while they are already exercising them in court. But Gifford Briggs of the Louisiana Oil & Gas Association wasn’t deterred Thursday. “We remain very optimistic about the legislation and its opportunity for ultimate and final passage,” Briggs said. “And we look forward to working with the (Edwards) administration and hopefully they will recognize the importance of having predictability, recognize the importance of the state being in the lead and the state being in charge of their own permits.”
Listen: LNG market disruption pushes developers to defer decisions on new liquefaction projects -- S&P Global Platts senior natural gas writer Harry Weber and S&P Global Platts Analytics head of gas and power Ira Joseph discuss the latest developments in the global LNG market as the weak price environment continues and project developers face challenges securing long-term contracts to finance new terminals. Amid supply and demand disruptions, decisions on new projects are being deferred to 2021 and perhaps beyond.
Magnolia LNG project sold for $2.25 million to British business with ties to Lafayette - The Australian parent company behind the Magnolia LNG project near Lake Charles sold the operation to a British business with a significant presence in Lafayette. Global Energy Megatrend Ltd. is expected to pay $2.25 million to LNG Ltd. in a deal slated to close on May 15, which includes all liabilities and those related to its 16 employees. The deal also includes patented liquefied natural gas technology. Global Energy Megatrend describes itself as an integrated natural gas company that has been leasing U.S. natural gas fields and investing in pipelines that lead to Louisiana ports and LNG export terminals. Ben Blanchet is the CEO of Global Energy Megatrend and is overseeing the company from offices in Lafayette. Blanchet is a major land owner in the Abbeville Salt Dome field and has experience contracting with the China National Petroleum Corp. and drilling in China. The company has been interested in the company behind Magnolia LNG long before the business became potentially insolvent, Blanchet said. "We have been in discussions with the company about these assets for quite some time," Blanchet said. The business expects to acquire more than just federal permits for the LNG export terminal. The deal includes land, detailed engineering plans and a contract for development, in addition to the underlying technology. "We're buying a company that is poised to more forward and develop that plant," he said. "They have done a terrific job in putting all those components together, but unfortunately they just ran out of money.
SUPREME COURT: Refiner wants justices to take up biofuel blending fight -- Friday, May 8, 2020 -- One of the companies at the center of a dispute over biofuel-blending requirements at small refineries said it wants the Supreme Court to take up the issue.
Saudi Oil Rush Threatens to Disrupt Stabilizing U.S. Market - An armada of tankers filled with Saudi Arabian crude steaming toward the U.S. threatens to prevent America’s oil glut from draining, which is only just beginning. Over 30 ships are set to arrive on the U.S. Gulf Coast and West Coast during May and June, according to ship tracking data compiled by Bloomberg. The more-than 50 million barrels of Saudi crude on the water threaten to upend a positive supply development: U.S. crude stockpiles declined for the first time since January and inventories at the Cushing, Oklahoma storage hub contracted by the most in months. The U.S. is facing a tsunami of Saudi oil -- the lingering effect of a price war between Riyadh and Russia back in March -- that led the Middle East nation to slash pricing of its grades to multi-year lows and flood the market. The wave of supply occurred even as the Covid-19 pandemic was beginning to rapidly weigh on petroleum demand. A fifth of global consumption is still seen disappearing this quarter alone. “The expected Saudi deliveries could push U.S. inventories back to builds depending on their timing,” said Sandy Fielden, director of oil and products research at Morningstar Inc. “If the shipments land at a rate that isn’t balanced by falling production or an uptick in exports, then we’ll see a domestic build.” The oil industry has been on edge for months with onshore and offshore storage capacity levels tested worldwide due to ballooning oil inventories spurred by the demand slowdown. On the U.S. West Coast, crude stockpiles are less than 5 million barrels short of reaching the region’s storage capacity. While data from the Energy Information Administration this week showed U.S. crude production dropped to the lowest in nearly a year, there are still volumes being produced that may have to jostle with new Saudi deliveries for storage space. “If all the Saudi tankers unload, the crude they carry will offset during May almost all of the production reductions from March levels, effectively maintaining the current high storage filling rates,”
Business has reopened in Texas, but the economy won’t be back anytime soon, experts say --The Texas economy has been protected unlike elsewhere in the country during some of the nation’s most devastating downturns.When the financial market crashed in 2008 and sent the United States into a recession, high energy prices provided the Texas economy with a sort of cushion. After the entire country eventually suffered from the financial squeeze, the number of oil rigs operating in the nation's top oil-producing state increased as the fracking revolution spurred an energy production boom in Texas.“When energy prices are high, that’s good for the state coffers in Texas,” said Steven Beach, dean of the College of Business at the University of Texas Permian Basin. “But it’s a bit of a drag on the economy elsewhere outside of Texas.”Now, as more people are out of work in the United States than ever before and the national economic calamity from the coronavirus outbreak has reached all corners of the country, business is back open in Texas. State officials have said they want the economy to roar back to the strength it had before the coronavirus. But unlike previous downturns, experts said this time the oil and gas industry, which recently saw oil prices dip into the negatives, might hold the state’s economy back.Demand for oil has plummeted during the public health crisis because people have not been flying, commuting or traveling due to the coronavirus pandemic. It's still not known when people's behaviors and habits might return to what they were before the ongoing pandemic. The country’s biggest oil companies have slashed budgets by billions, other companies have gone bankrupt, and what was once the world’s hottest oil field — the Permian Basin — is “so surreal, so quiet,” said Virginia Belew, regional services director at the Permian Basin Regional Planning Commission. “Word is that no one has ever seen it this drastic,” Jim O’Bryan, the top local official in Reagan County near Midland, said in an interview. “Hopefully it will be short lived. It’ll come back, it always has.”
Trump administration to buy 1 million barrels of oil for national stockpile - The Department of Energy (DOE) is planning to buy 1 million barrels of oil from U.S. companies after funding to make a larger purchase failed to pass Congress.A notice posted by the agency Wednesday calls the purchase “a test” for the Strategic Petroleum Reserve, a national stockpile President Trump in mid-March said he would fill “right up to the top.”The 1 million barrel purchase would be a far cry from the 77 million barrels of space within the reserve. Doing so would have required $3 billion in funds, which Congress did not appropriate as part of the CARES Act stimulus package.The effort comes as oil prices have fallen to historic lows due to a lack of demand and a lack of storage space for an oversupply of oil.Democrats have repeatedly spoken out against any effort to assist the oil and gas industry during the coronavirus pandemic.“Using federal assistance — including low-interest loans, royalty relief, tax breaks, or strategic petroleum reserve purchases — in order to prop up oil companies would be a wasteful misuse of government resources that would exacerbate the climate crisis,” Sens. Bernie Sanders (I-Vt.), Ed Markey (D-Mass.) and Jeff Merkley (D-Ore.) wrote in a letter to the president when the idea was first floated. In April, DOE announced it would instead rent 23 million barrels of storage space in the reserve, allowing companies to pay for the space in oil. The 1 million barrel purchase would be open to small and mid-sized oil and gas companies. The Federal Reserve Board also tweaked its Main Street Lending Program to be accessible to the same size oil companies. Energy Secretary Dan Brouillette told Bloomberg TV on Wednesday that he and Treasury Secretary Steven Mnuchin were asked by President Trump “to evaluate the programs that were passed by the Congress and ensure that there is access for these energy industries to those programs.”
Is EIA Data Disguising A Disastrous Decline In U.S. Shale? - U.S. oil production continues to decline as drillers shut in wells and cut back spending. Output has already declined by 1.1 million barrels per day (mb/d), and more losses are likely. New data from Rystad Energy predicts U.S. oil production declines of roughly 2 mb/d by the end of June.“Actual production cuts are probably larger and occur not only as a result of shut-ins, but also due to a natural decline from existing wells when new wells and drilling decline,” Rystad said in a statement.Energy expert Philip Verleger, in an article for Energy Intelligence reports that the magnitude of output declines is much larger. His latest research shows that production as of May 10 is down by almost 4 million bpd from its peak as the below chart shows. To be sure, the U.S. government is doing quite a bit to try to bailout the oil industry. A new report finds that some 90 oil and gas companies will benefit from the Federal Reserve’s corporate bond buying program. The Trump administration is also quietly reversing environmental protections on the oil and gas industry.But in the face of a historic meltdown in the oil market, even handouts from Uncle Sam won’t stop declines. The U.S. oil industry continues to idle drilling rigs at a tremendous clip, and the rig count is down by more than half in two months. “[W]e think that the last time there was so little drilling activity in the US was the 1860s during the first decade of the Pennsylvania oil boom,” Standard Chartered analysts said. The investment bank said that the contraction was notably acute in Oklahoma, where rigs fell to just 11 across the state, down 89 percent from the same period a year earlier. The sharp decline in rigs, drilling and completion activity means that the steep decline rates endemic to shale drilling will overwhelm what little new production comes online. Standard Chartered said that if activity were to remain stuck at current levels, U.S. production in the five main shale basins would fall by 2.89 mb/d by the end of 2020. Those declines would come on top of the output that has only been shut in temporarily. Standard Chartered envisions a “squashed-W pattern” for supply, in which temporarily idled output comes back online in a few months, but more structural declines continue thereafter.The EIA, characteristically, is much more optimistic about the state of U.S. supply. The agencysaid on Tuesday that it only sees a 0.5 mb/d decline in oil production this year, compared to 2019 levels. Notably, Secretary of Energy Dan Brouillette says production will increase in the third and fourth quarters as the economy roars back.Others aren’t so sunny. A report from Wood Mackenzie released on Wednesday says that oil demand will take years to recover. “Production is falling sharply in the US, and some producers are reluctant to sell forward,” Commerzbank wrote in a note.
US Oil, Gas Permitting at Record Low in April, but Strengthening Seen in Early May - The collapse in drilling activity deepened in April, with permitting for oil and natural gas wells at a record low, but there are glimmers of gains so far this month, according to an analysis by Evercore ISI. Using week/week (w/w) data, Evercore said oil permits climbed 19% from the final week of April to 166 in the first week of May. The Permian Basin accounted for the most permits early this month, rebounding to 100, up by 35 from the week before. The gain was partly offset by the Eagle Ford Shale, with six fewer permits, and the Mississippian Lime, down by seven.Still, natural gas permits “strengthened to 39,” a 64% gain w/w, “as a result of resilience in the Haynesville Shale,” which added 15 permits. Permitting in other onshore plays dropped to 65, down by 37 from late March. For natural gas, permitting has been hit and miss since the start of the year, according to Evercore. Marcellus Shale permitting plunged by 44% through April year/year and was down by 20% from March to 169. The Utica Shale, a mix of gas and liquids, saw a month/month (m/m) decline of 14 permits. However, the Haynesville, second to the Marcellus in dry gas production, posted a slight recovery from March, with permits up by 13.Year-to-date through April, gas permitting across the country decreased by 39% to 884, “resulting from lower applications in the Marcellus to 409,” off 44% year/year, “and the Haynesville to 383,” down 31%. In Texas, where the bulk of the country’s oil and gas is produced, permitting moved to its lowest count in more than 10 years during April and fell 28% year to date, Evercore said.Permits by the oil and gas majors, which dominate in the Permian, were off in the first four months by 25% from the same period in 2019.U.S. onshore permits in April overall fell by 2% from March to 2,013, “primarily as a result of declines in the Gulf Coast (minus 26%) and Midwest (minus 59%),” West said. “Excluding ‘other’ shale plays, drilling permits marked the lowest total in our dataset going back to 2006 at 1,001.”For individual plays, the m/m declines were led by the Permian, off 159 from March, and in the Eagle Ford Shale, down by 74. Lower permit counts also were reported in the Granite Wash formation, down by 16, and in the Barnett Shale, off 13.Wells permitted during April in the West Texas portion of the Permian “declined to 504 (minus 24% m/m) due to curtailments in Howard, Reeves, Loving and Midland counties, where aggregate permit applications declined to 144 (minus 128 m/m).” Contributing to the decline in permits during April was the pullback by some of the biggest operators in Texas, including EOG Resources Inc., which requested 26 fewer permits than in May. ExxonMobil’s requests were down 26 m/m, while Permian pure-play Diamondback Energy Inc. had 18 fewer requests. BP plc requested seven fewer permits than in March.In the Eagle Ford, the second largest play in Texas, permitting contracted in April to 94, off 44% m/m. State regulators granted authorization to drill 480 oil and gas wells in the Permian, with the New Mexico portion accounting for 46% of the activity, West said. New Mexico activity was driven lower by public operators, whose permit applications fell to 142 in April, down by 19 m/m.Through April, overall drilling permits across the country fell by 61% year/year to 8,751.
Federal Judge: Pipelines Must Not Cross Streams Without Considering Endangered Species - A federal judge upheld his April 15 ruling Monday, tossing a key permit required by the Keystone XL and other pipeline projects to cross streams and wetlands.Montana U.S. District Judge Brian Morris affirmed that the U.S. Army Corps of Engineers cannot use a blanket water-crossing permit to approve new oil and gas pipelines without considering their impacts onendangered species."The court rightly ruled that the Trump administration can't continue to ignore the catastrophic effects of fossil fuel pipelines like Keystone XL," Center for Biological Diversity (CBD) senior attorney Jared Margolis said in apress release. "Constructing pipelines through rivers, streams and wetlands without analyzing the impacts on imperiled species is unconscionable. We'll continue to fight to protect vulnerable species, our waters and the climate from this kind of reckless development."At stake is a permit called Nationwide Permit 12, which the Army Corps uses to fast-track approvals for construction across waterways, The Associated Press explained.Morris ruled in April that the Army Corps did not consult with the Fish and Wildlife Service as to how these crossings would impact endangered species when it renewed the permit in 2017, Reuters reported.Morris' April ruling was in response to a lawsuit brought by environmental groups focusing on the approval process for the Keystone XL pipeline specifically. However, the ruling blocked the use of Nationwide Permit 12 for all projects, CBD explained.Utility groups and the government asked Morris to alter his ruling, arguing that it interfered with thousands of construction projects, according to The Associated Press. In response, Morris said that the permit could be used for electrical lines or pipeline repairs, but not the construction of new oil and gas pipelines."To allow the Corps to continue to authorize new oil and gas pipeline construction could seriously injure protected species and critical habitat," Morris wrote, according to The Associated Press. The ruling does not actually block construction work on Keystone XL or other pipelines, but it is another setback for the long-delayed project, since it now cannot build across streams without further environmental review.
Company underestimates North Dakota brine spill — An estimated 35,700 gallons of produced water spilled over a week ago at an oil well pad in McKenzie County, N.D., according to a press release from the state Department of Environmental Quality. Produced water, or brine, is a mixture of saltwater, oil and sometimes, drilling fluids, that is created as a byproduct of oil and gas production. The spill, which occurred about 10 miles northeast of Keene, impacted nearby farmland. The incident was caused by a leak in a small pipeline to the produced water storage tank. Newfield Production Co., which was responsible for the spill, estimated that only 1,260 barrels of brine had spilled when it reported the incident to the state. Later investigation found the company had significantly underestimated the magnitude of the spill. It's unclear if the company accidentally reported incorrect information or purposefully misled the department. A representative of the department did not respond in time for publication of this article. The department said officials will continue inspecting the site and monitoring remediation efforts.
North Dakota aims to use COVID-19 aid to plug oil wells (AP) — North Dakota wants to use $33.1 million in federal coronavirus aid to plug “orphaned” oil wells, many of which have been abandoned by companies financially disrupted amid low energy prices and sparse demand brought on by the pandemic. State and industry officials said the idea is both a jobs program for energy workers and an attempt to curb a growing problem in western North Dakota’s oil patch. The North Dakota Emergency Commission, headed by Republican Gov. Doug Burgum, approved the funding Tuesday. The commission in total approved $524 million, or 42% of the $1.25 billion given to the state as part of the federal stimulus package approved in March. Burgum said the money approved by the commission is to support economic recovery. The state’s Budget Section, which handles the Legislature’s business between sessions, is scheduled Friday to consider the program, along with a package of proposals from several state agencies. State Mineral Resources Director Lynn Helms said 549 wells have been identified as abandoned in North Dakota’s oil-producing region, including about 10% that companies have walked away from in recent weeks. Before the pandemic devastated the U.S. oil industry, daily oil production in North Dakota was at a near-record 1.45 million barrels daily in February, the latest figures available. Helms said thousands of wells have been idled in recent weeks, amounting to about 550,000 barrels of lost oil production daily, or more than third of the state’s production from a few months ago. Companies are required to post a $100,000 bond for a producing oil well but the cost of plugging and reclaiming a site averages about $150,000, Helms said. The problem, Helms said, is that the oil companies don’t have the money needed to plug and reclaim the sites, and bonding companies are not willing sell more bonds to cover the costs. Plugging an orphaned well consists largely of filling it with cement and sealing it. Helms said it takes a crew of about 15 about five days to plug a well.
There Are Green Jobs Hiding in the Oilfields - Jobs and towns built on fossil fuel extraction appear to be headed for disaster. The Trump administration seems inclined to respond by throwing aid at the oil and gas CEOs who helped to engineer the indebted industry’s current predicament. The Resources for Workforce Investments, not Drilling, or ReWIND, Act introduced last week would prevent an outright bailout for corporate polluters. Less attention has been paid to how to protect the communities who stand to lose the most from plummeting oil prices, even as both drillers and oilfield services companies furlough and lay off tens of thousands of people—moves that will wreak havoc on state and local tax bases. Texas alone could shed a million jobs this year as a result of the downturn. Capitol Hill still seems uninterested in imagining a future without fossil fuels. But in April, drillers shut down more oil drilling rigs in the United States than have been cut since the last price crash in 2015. Many will not come back online anytime soon. More than half of oil and gas workers could lose their jobs. To blunt the impact, oil-producing states have asked the Trump administration to pay laid-off workers to start plugging the country’s roughly two million abandoned wells. There would be some precedent for this, both abroad and domestically. Canada announced the creation earlier this month of a $1.7 billion fund to clean up wells in Alberta, Saskatchewan, and British Columbia. The fund is expected to create 5,200 jobs in those three provinces. And in the United States, the federal government already pays to clean up lots of bankrupt oil companies’ abandoned wells. Since it’s already something of a sunk cost, the oil-producing states’ request could present an opportunity for the federal government for a jobs program that will pass muster in red states. Lawmakers could decide to put a few thousand people to work in some of the places where layoffs in the extractive sector are hitting hardest. Whether through a federal job guarantee or some sort of paycheck-protection program that mandates fossil fuel companies pay workers to do something other than extract oil, the government might be able to address unemployment and help the planet at the same time. . Beyond extraction sites, about half of the country’s 450,000 contaminated lands, known as brownfield sites, are believed to owe that designation to petroleumissues, including from the leakage of storage tanks buried under gas stations. There’s a vast amount of work to be done not just plugging wells but restoring landscapes scarred by fossil fuel development.
Federal agency sides with North Dakota in oil-by-rail dispute with Washington state -- A federal agency has sided with North Dakota and Montana in a dispute over a new Washington state law that places restrictions on shipments of oil by rail in an attempt to boost safety. The U.S. Pipeline and Hazardous Materials Safety Administration issued the decision Monday, nearly 10 months after North Dakota and Montana petitioned the agency to overturn the law, arguing that it amounted to a “de facto ban on Bakken crude.” The Washington Legislature passed a bill last spring requiring that oil unloaded from trains have a vapor pressure under 9 pounds per square inch. The limit falls below North Dakota’s cap, 13.7 psi, which is based on an industry standard. PHMSA Chief Counsel Paul Roberti wrote in the decision that federal law and regulation surrounding the transportation of hazardous materials “preempts” the vapor pressure limit that Washington set. He said Washington’s limit, if it were to stand, “would set an alarming precedent.” “Other State and local jurisdictions would be encouraged to enact their own vapor pressure limits for crude oil,” he said. “The resultant multiple and conflicting requirements will undermine the uniform Federal regulatory scheme.” Roberti said the Washington law creates a new class of crude oil that differs from federal regulation and establishes different rules for handling oil. He added that Washington’s new requirement “is an obstacle to accomplishing and carrying out” federal law.
Refugio oil spill settlement up for discussion on Wednesday - The settlement of the Refugio Oil Spill includes $22.3 million for the remediation of natural resource losses, such as injuries to birds and marine mammals, subtidal and shoreline habitat restoration, and compensation for recreational losses. Two online town hall meetings are scheduled for Wednesday, May 13, to present the 173-page Draft Damage Assessment and Restoration Plan for these projects and to discuss public comments.One session runs 1-3 p.m., and the second 6-8 p.m. Register for the webinar here, and a system checkhere prior to the seminars is advised.Written comments are due by June 8, 2020, and can be emailed to firstname.lastname@example.org or mailed to: Refugio Beach Oil Spill Natural Resource Trustees, C/O Ventura Fish and Wildlife Office, 2493 Portola Road, Suite B, Ventura, CA 93004, Attn: Michael Anderson, California Department of Fish and Wildlife; Jenny Marek, United States Fish and Wildlife Service.
About all those oil tankers off the coast of California - The U.S. oil market was in a tailspin when dozens of oil tankers began approaching California’s coast in late April. The vessels, some as long as three football fields, were filled with millions of barrels of oil that suddenly had no place to go. Amid the combined effects of a price war between oil-rich states Saudi Arabia and Russia and the COVID-19 pandemic’s curbing of demand, American refineries slashed production while onshore facilities filled to the brim. As a result, U.S. oil prices plunged to negative levels for the first time in history. Tankers are still anchored near southern California today, and as they wait, they’ve switched from running their primary diesel engines to smaller auxiliary engines. While idling doesn’t create the carbon emissions of actually transporting cargo, the fleet is still generating the equivalent daily footprint of driving roughly 16,000 passenger cars. The giant ships burn fuel to keep lights on, power equipment, and heat the large volumes of crude oil resting in their tanks. Given the turbulent economy, oil analysts say the tankers might sit in suspended animation for weeks or months. In recent days, as many as 32 tankers were anchored near Los Angeles and Long Beach, with some vessels leaving and new ones arriving as oil very slowly trickles in and out of ports. On May 11, 18 tankers filled designated spots as if in a “truck stop parking lot” three miles offshore, said Captain Kit Louttit, who monitors port traffic for the Marine Exchange of Southern California. That is about triple the typical number of tankers in those spaces. Tankers along the U.S. West Coast, mainly off of California, held some 20 million barrels of oil on Monday, or nearly enough to satisfy a fifth of the world’s daily oil consumption, according to market data firm Kpler. The floating supply glut should gradually clear once new deliveries from the Middle East and Asia stop arriving. But while the idling ships remain near California, they “could pose an ongoing risk to air quality,” said Bryan Comer, a senior researcher at the environmental think tank International Council on Clean Transportation, or ICCT. “Especially because you have these ships lumped together.” The cluster, he noted, concentrates the pollution that drifts ashore.
Shoreline oily water cleanup begins at Valdez -Spill response efforts at Port Valdez are continuing nearly a month after discovery of an oil sheen at the Valdez Marine Terminal. Some boom has been removed, and shoreline cleanup has begun in oiled areas within the primary containment boom. The cause of the spill remains under investigation, with early indicators suggesting the Alaska North Slope crude oil/water mixture leaked from a sump that overflowed. Alaska Department of Environmental Conservation officials said that having determined that the threat of the spill of a mixture of crude oil with water is now limited, the spill management process is looking to scale back while continuing its response to finish the cleanup. Primary containment boom remained in place around the spill outflow area, shoreline impact surveys were completed, and limited impacts were observed with no areas outside of the Valdez Marine Terminal’s shoreline. Boom had previously been deployed to protect the Solomon Gulch Hatchery, the Valdez Duck Flats, Saw Island and Seal Island. Responders concluded that these sensitive areas were no longer at risk for exposure to oil and protection boom was removed from the Solomon Gulch Hatchery and Valdez Duck Flats. Protection boom for Saw Island and Seal Island was approved for removal next. The latest DEC update on the cleanup said that oil skimming operations had removed 53,340 gallons of oily water and that 665 gallons of oil had been recovered. The primary containment boom was adjusted to contain the spill closer to the spill outflow area. The bigger boom was still in place to maintain the outer perimeter of the boomed areas and was being monitored to ensure adequate containment. Response crew were continuing oil skimming operations and use of sorbents for passive recovery.
Future(S) Games, Part 2 - The Baffling Impact Of Oil Futures On Physical Contract Prices - CMA Roll Adjust And P-Plus --On April 20, that fateful day in crude oil markets when the CME May contract for WTI at Cushing collapsed to negative $37.63/bbl, the number of contracts involved in the chaos was relatively small. So you might think that most producers sat on the sidelines, watching Wall Street paper traders writhe in stunning financial pain. But not so. Almost all producers saw their crude prices that day crashing in exactly the same magnitude. That’s because the daily price of the CME WTI contract is part of the formula pricing used in a very large portion of crude oil contracts in U.S. markets, both directly and indirectly. There are two formula mechanisms that are commonly used in crude oil sale/purchase contracts that are responsible for that linkage: the CMA and WTI P-Plus. These arcane pricing mechanisms are complicated, but in order to understand U.S. crude markets, it is critically important to appreciate how they work. Today, we continue our deep dive into crude oil contract pricing mechanisms. The CME NYMEX WTI crude oil futures contract is the underlying benchmark in nearly all U.S. domestic crude price contracts. Differences between futures and physical trading arrangements make pricing physical WTI barrels complex. Two formula mechanisms are commonly used in physical transactions that link directly to the NYMEX settlement prices — the CMA and WTI P-Plus — and so both contract types felt the impact of last month’s price collapse. As we said in Part 1, the CME NYMEX WTI futures contract is the most liquid — or most widely and actively traded — commodity futures contract in the world, and is so ubiquitous that it also underpins domestic U.S. crude contract markets. It’s a strange symbiotic relationship, in that not only do cash crude prices heavily influence futures prices, but the cash contract price for most U.S. crude is indexed to the futures price. Differences between futures and physical trading, as well as the delivery mechanism that links the two markets, make pricing physical WTI complicated.
CFTC Warns Traders Oil Prices Can Turn Negative Again - With just one week left until the expiration of the June WTI contract, whose open interest is still a whopping 270K contracts equivalent to 270 million barrels that may soon require a physical delivery spot...... and some traders getting flashbacks to the catastrophic oil price crash on April 20, today the CFTC poured gasoline on the smouldering fire when it warned that oil futures contracts could again trade with negative prices during the coronavirus pandemic.As Bloomberg and Dnyuz reports, the Commodity Futures Trading Commission will advise exchanges to monitor their markets and remind them to "maintain rules to provide for the exercise of emergency authority”, including the power to “suspend or curtail trading in any contract” if markets become disorderly, according to an advisory notice to be released on Wednesday.“We are issuing this advisory in the wake of unusually high volatility and negative pricing experienced in the May 2020 West Texas Intermediate (WTI), Light Sweet Crude Oil Futures contract on April 20,” says the eight-page advisory signed by the CFTC’s heads of market oversight, clearing and risk, and swap dealer and intermediary oversight.Clearing houses "should prepare for the potential that certain contracts may experience significant price volatility, and that negative pricing is a possibility", the advisory said adding that "we are issuing this advisory in the wake of unusually high volatility and negative pricing experienced in the May 2020 physically-delivered WTI contract, and related reference contracts."The alert comes after the US benchmark West Texas Intermediate oil contract plunged below $0 a barrel last month for the first time, as buyers searched for places to store a glut of oil. The WTI contract for June delivery is scheduled to expire next Tuesday, raising the prospect of a repeat of the chaotic final two trading days in the May oil contract, which settled at minus $37.63 a barrel on April 20.The move caused losses for countless retail traders and at least one futures broker, and sparked widespread criticism of an oil benchmark referenced by drillers, refiners, consumers and investors.A senior CFTC official said its notice applied to all contracts, not just oil, and did not represent a forecast that negative oil prices would return. “We are not predicting the market. We’re just suggesting planning,” the official said. Brokers “should prepare for the potential that certain contracts may experience significant price volatility and, possibly, negative pricing,” the CFTC said.
WHITE HOUSE: Trump says oil moving 'to greatness.' 4 reports disagree -- Wednesday, May 13, 2020 -- President Trump said yesterday that the oil industry is turning the corner, and his Energy secretary echoed the enthusiasm, insisting in two interviews that the industry is on the verge of what the administration calls a "transition to greatness."
Coronavirus leaves experts pondering if the planet already hit peak oil demand -- Here's a wild but no-longer-unthinkable idea: Is it possible that global oil demand will never again exceed pre-pandemic levels? The timing of peak demand has big implications for carbon emissions, oil-producing nations and the industry. Many prior analyses concluded that it's a rather remote horizon, ranging from the late 2020s to the 2040s or later, though needless to say there are lots of variables. “Will demand ever go back to where it was? That is hard to say,” Shell CEO Ben van Beurden told Bloomberg late last week. He also said the odds of demand peaking this decade have risen. Until recently the world used roughly 100 million barrels of oil per day.But COVID-19 has crushed demand, with multiple analysts seeing a roughly 25%–30% decline or more at the height of the lockdowns, though recovery has begun. The International Energy Agency estimated in mid-April that demand was down by 29 million bpd that month, the trough before a recovery that still brings a year-over-year drop of 9 million bpd. BNP Paribas Asset Management analyst Mark Lewis believes 2019 may have been the peak.He said in a mid-April Financial Times piece (subscription) that some current demand loss could be permanent, such that consumption hangs around in the 95 million to 100 million bpd range for several years before long-term decline begins. "[C]onsider the structural pressures on the oil market already in evidence before coronavirus hit and then add to these the behavioral changes prompted by the pandemic, some of which seem likely to stick," he wrote.Meanwhile, CNN reports that while the consultancy IHS Markit sees demand coming back to 2019 levels by 2022, they've also modeled a scenario in which a second virus wave leads to demand never coming all the way back. The idea that peak demand just happened is not the mainstream view, though Bloomberg notes a "growing minority" are speculating about it. But what's clear is that COVID-19 could at least hasten the arrival of the moment when it stops rising entirely.
BP boss Bernard Looney: Peak oil demand may have just happened – Add BP CEO Bernard Looney to the list of people who think oil demand may never fully recover after the coronavirus pandemic, even though it's already coming back from the depths of the collapse. “I don’t think we know how this is going to play out. I certainly don't know,” he told the Financial Times (subscription).“Could it be peak oil? Possibly. Possibly. I would not write that off," he said in the interview, where he notes the proliferation of remote-working technology. The remarks show how COVID-19 has upended oil markets in a way that's likely to last for a long time. Looney's comments are similar to recent remarks by Royal Dutch Shell CEO Ben van Beurden. An Oxford Institute for Energy Studies analysis sees demand reaching "pre-shock" levels in the fourth quarter of 2021. But they also cite modeling challenges and known unknowns, such as whether there's another wave of lockdowns — a prospect other analysts are weighing too. "It may be hard to comprehend now. But barring a second wave of the pandemic, nearly all pre-COVID demand could return by the second half of 2021," IHS Markit's Roger Diwan said in an email.
The Fed Just Changed Its Own Rules to Bail Out the Fossil Fuel Industry - Alexis Goldstein - The fossil fuel industry and the Senate GOP had been lobbying the Fed hard for changes to help big oil. One of the changes they sought was the ability to use emergency loans to pay down or refinance other debts. Heavily indebted fossil fuel companies are teetering on the edge of bankruptcy and under increasing pressure from their lenders, like the big banks to whom the sector owes $200 billion. In the case of one big bank, Wells Fargo’s portfolio of loans to energy companies is so distressed, it’s been described as a “bloodbath.” Two fossil fuel companies have already declared bankruptcy since April — Whiting Petroleum and Diamond Offshore. Desperate to prop up these failing firms, Sen. Ted Cruz complained to the Fed in an April 24 letter that oil and gas firms needed help, because the original Main Street Lending Program terms explicitly prevented companies from using the funds to “repay or refinance pre-existing loans,” and that made them vulnerable to bankruptcy. A trade group for big oil, the Independent Petroleum Association of America (IPAA), made the very same complaint. On April 30, the Fed gave the oil industry precisely what it asked for,expanding the lending programs to allow more debt, looser standards and bigger loan amounts to accommodate the oil industry. The changes allow companies to use taxpayer-backed emergency relief funds to refinance and pay down pre-existing debt. The very same day the Fed acted, Chesapeake Energy was about to go bankrupt. But these and other changes the Fed made benefited both Chesapeake and a host of other oil companies. Previously, businesses with large amounts of debt were not able to get large loans, another thing Senator Cruz complained about. The senator got what he asked for when the Fed raised the threshold to allow more heavily indebted companies to participate. The Fed also gave the industry more flexibility to play accounting games to make their earnings look rosier for the purposes of that threshold, changes that benefited both the teetering Chesapeake Energy, but also Occidental Petroleum. Former Trump adviser and mega-donor Carl Icahn has a nearly 10 percent stake in Occidental. And this isn’t even the only change that benefitted Occidental. Previously, firms using the Main Street Lending Program could have no more than 10,000 employees. The Fed raised it to 15,000. Occidental Petroleum just so happens to have 14,400 employees. Yet another oil sector request the Fed granted was Energy Secretary Dan Brouillette’s ask to raise the cap on one of the loan programs from $150 million to $200 million. Big oil isn’t just getting the supposedly independent Fed to change the rules to stay afloat despite a decade of bad bets. Taxpayer funds are now effectively being used to reduce debt costs for oil companies and bail out their Wall Street creditors. While some argue that the Fed’s Main Street Lending Program isn’t taxpayer money, this is inaccurate: the program uses $75 billion from the CARES Act to partially cover any losses these loans incur for the Fed. At the end of the day, taxpayer money is being used as a down payment for loans to big oil. Those who benefit the most are those who’ve loaned money to big oil — banks and bondholders. Those that justify these loans do so on the basis that they support jobs, but the connection to actual worker protections are minimal, as the Feddoesn’t explicitly bar firms who take these loans from laying off their employees.
Oil and gas companies asked, then received changes to Fed coronavirus stimulus program - Oil and gas companies in Pennsylvania could benefit from a change to a Federal Reserve stimulus program aimed at helping businesses during the coronavirus pandemic.Critics have attacked the changes, calling them a “stealth bailout” for heavily indebted oil and gas companies. The changes were made in late April to the Fed’s Main Street Lending program, part of the $2 trillion coronavirus relief bill passed by Congress in March. The$600 billion loan program is intended to help small- and medium-sized businesses that were in good financial shape before the pandemic struck. When the Fed rolled out the program, it prohibited companies from using the loans to pay off debts. Oil and gas companies and their advocates asked the central bank to loosen up those guidelines. One of their biggest asks: They wanted to be allowed to use the loans to pay off other debts, too. The Fed’s final guidelines gave those companies their wish — companies could use the loans to pay off some types of debt. And the maximum loan size increased from $150 million to $200 million. Oil-state Sens. Ted Cruz of Texas and Kevin Cramer of North Dakota praised the changes. “It’s another arrow in the quiver” to help the oil industry in his state, Cramer said in a video statement. Environmentalists questioned whether the government should be throwing a lifeline to the fossil fuel industry — one of the country’s biggest sources of greenhouse gases. Emissions must be cut dramatically, scientists say, if the world is to avoid the worst effects of climate change. Others saw the Federal Reserve — an independent institution that is supposed to stay outside politics — giving preferential treatment to a powerful industry with substantial ties to the Trump administration. “This is an oil bailout for a specific set of companies,” said Graham Steele, the director of the Corporations and Society Initiative at Stanford Graduate School of Business.Steele, a former aide to Democratic Senator Sherrod Brown of Ohio, said the program is risky because climate change risks making these companies’ assets — oil and gas reserves — “stranded assets” in the future, if governments tax carbon to avert runaway climate change. He said the loans are also risky because many of the companies were doing poorly before the pandemic. “(The Fed) had structured the program in a way so as not to lose taxpayers’ money. And now members of Congress and industry have lobbied them. And under that pressure, they have buckled. They have changed the program to help out a specific industry,” Steele said. The Federal Reserve says changes to the program weren’t made with the oil industry in mind, and that other industries could benefit. Business groups like the U.S. Chamber of Commerce also lobbied for the changes. But observers see the Fed’s revisions to its lending guidelines as a clear win for oil and gas companies. David Livingston with Eurasia group, a risk management firm, said the changes are especially good for oil and gas companies because of the high amount of debt some have accumulated. “They were sort of running on a treadmill and the entire shale enterprise was increasing its production month over month, year over year over year, in large part, thanks to the continued provision of relatively low cost capital,” Livingston said.The idea behind the strategy was that prices for oil and gas would eventually rise and they’d be able to pay off their debts. But the opposite has happened, at least for oil. It plummeted into the negative range in April, though prices are recovering. The loans could also help natural gas companies that operate in Pennsylvania. A group of GOP senators from Pennsylvania and other Appalachian states wrote in favor of the changes in April.
Oil Stockpiles Have Stopped Growing in World’s Biggest Buyer - The great oil glut of 2020 may have already peaked in the world’s biggest crude importer. Crude inventories in China have shrunk in recent weeks after rising to record levels, according to analysts and satellite observations. Supplies have been drawn out of storage as refineries ramp up operations to meet rising demand from an economy emerging from lockdown. Inventories drawing in the world’s biggest importer is an early sign that rebalancing may have begun in the global oil market after an epic collapse in demand, according to Morgan Stanley. Stockpiles dwindled even as oil imports in April increased from the previous month, according to Customs data. “The combination of inventories falling and strong imports implies really solid refining activity,” said Geoffrey Craig, an analyst with Ursa Space Systems Inc., which uses synthetic aperture radar to track storage tank fills. “You saw them build aggressively in late February and into the end of March, and since then they’ve absolutely plateaued and have come off a bit.” Refiners are drawing oil out of inventory to process into gasoline and diesel as traffic once again snarls China’s cities following the lockdown earlier this year to halt the spread of the coronavirus. Even as driving demand dries up in the rest of the world, rush hours from Beijing to Shenzhen at the end of last month are busier than they were in the same period last year. Meanwhile subway ridership remained about 50% below pre-virus levels in Beijing and about 30% below in Shanghai, according to data compiled by BloombergNEF, as fears of large crowds push commuters toward the relative isolation of cars. Independent refiners in Shandong in northeast China are operating at record rates, while state-owned giant PetroChina Co. said it was ramping up fuel production after it fell in the first quarter.
China crude oil runs rebound in April as fuel demand picks up - (Reuters) - China’s daily crude oil throughput rebounded in April from a 15-month low in March as refiners cranked up operations to meet renewed fuel demand after lockdowns imposed to prevent the spread of the coronavirus outbreak were eased. The country processed a total of 53.85 million tonnes of crude oil last month, data from the National Bureau of Statistics (NBS) showed on Friday, equivalent to about 13.1 million barrels per day (bpd). That was some 11% higher than 11.78 million bpd in March. The agency said on Friday it had adjusted the database of industrial enterprises it uses to help compile a range of production numbers. On that basis, Friday April’s crude oil throughput was 0.8% above the year-ago level, it said; a Reuters calculation using NBS data from last year put the rise at 3.4%. “In terms of year-on-year percentage change, we only included the companies that existed in both years,” a spokesperson from agency’s media relations department told Reuters. “For instance, if a company existed in 2019 but does not exist in 2020, then their figure in 2019 will not be included in 2020 year-on-year percentage calculation.” Analysts said it would not be not surprising for the agency to revise its year-ago numbers.
China's top energy firms to grow gas output despite spending cuts - (Reuters) - China’s top energy producers will grow their natural gas output this year by twice as much as in the previous oil rout even as they slash spending due to collapsing oil prices, company officials and analysts said. The world’s top energy consumer is forecast to expand its natural gas production by 5% or more in 2020 despite plans for deep spending cuts which will likely curb local oil production, they said. That would be half the growth in 2019 but double the 2.2% growth seen in 2016 following a lengthy oil slump. China’s state-owned energy companies are joining others worldwide in slashing expenditure after this year’s 56% drop in oil prices as a global pandemic ravaged economic activity. As the country’s oil and gas trio plan double digit spending cuts, they are prioritising gas development at home particularly as the market is relatively insulated from sharp oil moves due to government subsidies. “Under the capital expenditure cuts, companies are revising their gas strategy from an earlier aggressive push to a more practical approach, as gas production remains profitable,” said Zhu Kunfeng, Beijing-based associate director at IHS Markit. PetroChina, Sinopec Corp and CNOOC Ltd said in April they would reduce spending by roughly 20% to 30%, similar to the cuts they made in the last oil rout in 2015/2016.
Goldman Sachs' Jeff Currie warns jet fuel demand may never fully recover from the coronavirus crisis - The coronavirus outbreak will have a lasting impact on the behavior of businesses across the globe, with jet fuel demand unlikely to ever fully recover, according to the head of commodities research at Goldman Sachs. The Covid-19 pandemic has meant countries have effectively had to shut down, with many governments imposing strict restrictions on the daily lives of billions of people. Confinement measures — which vary in their application worldwide but broadly include school closures, bans on public gatherings and social-distancing guidelines — have been implemented in 187 countries or territories in an effort to try to slow the spread of the virus. To date, more than 4.1 million people have contracted Covid-19 worldwide, with 282,727 deaths, according to data compiled by Johns Hopkins University. The public health crisis has led to an extreme demand shock in energy markets, with world travel brought close to a standstill. Jeff Currie of Goldman Sachs argued that the severe loss of oil demand came primarily from three sectors: Commuting demand; industrial demand and jet demand. Industrial demand and commuting demand should both be able to recover fairly quickly from the pandemic, Currie said, but jet demand "is the weakest one." "So far, we would tend to think when we see a normalization globally, you'll get the leisure demand back. The part I don't think you get back is what we are doing right now," Currie said during a video call with reporters on Thursday. "I think you are going to lose a good chunk of the jet demand that would have been associated with business travel. Our base case is you lose somewhere around 2 to 3 million barrels per day of that," he added.Goldman Sachs expects global oil demand to fall to 94 million barrels per day in 2020, down from 100 million barrels per day in 2019. Oil demand is then expected to rise to 99 million barrels per day in 2021. Currie said the U.S. investment bank does not expect oil demand to normalize back to pre-crisis levels until the third quarter of 2022.
Oil prices drop amid supply glut, fears of 2nd coronavirus wave - Oil prices fell on Monday as concern over a persistent glut and economic gloom caused by the coronavirus pandemic combined to cancel out support from supply cuts at some of the world's top producers. Brent crude futures were down 29 cents, or 0.9%, at $30.68 a barrel by 0431 GMT, while U.S. West Texas Intermediate crude futures fell 17 cents, or 0.7%, to $24.57 a barrel. Both benchmarks have notched up gains over the past two weeks as countries have eased business and social lockdowns imposed to cope with the coronavirus and fuel demand has rebounded modestly. Oil production worldwide is also declining. But possible signs of a second wave of coronavirus infections in northeast China and South Korea worried investors even as more countries started to pivot towards easing pandemic restrictions in moves that could support oil demand. Goldman Sachs analysts said there was still concern that demand will stay weak in 2021, with worries about a second wave of Covid-19 cases and only a modest increase in personal or corporate travel. Global oil demand has plummeted by about 30% as the coronavirus pandemic curtailed movement across the world, building up inventories globally. Fears that the United States is running out of storage space triggered WTI prices crashing into negative territory last month, prompting some U.S. producers to slash output. In a sign of that impact, the number of operating oil and gas rigs in the world's largest oil producer fell to 74 in the week to May 8, a record low according to data released on Friday from energy services firm Baker Hughes going back to 1940. "People are surprised by how quickly the U.S. is shutting in production and that's exactly what we need in order to support prices," said Tony Nunan, a senior risk manager at Mitsubishi Corp in Tokyo. "There's another 10 days before the June contract expires ... if the WTI contract can avoid a crash going into expiry, hopefully we've seen the bottom."
Oil turns positive as Saudi Arabia to cut production by an additional 1 million barrels per day - Oil prices jumped to their highs of the day after Saudi Arabia said it will cut production further in an effort to support global oil markets. Beginning on June 1 the Kingdom will cut output by an additional 1 million bpd, which combined with the cuts agreed to by OPEC and its oil-producing allies, brings Saudi Arabia's total cut to roughly 4.8 million bpd below its April record production level. Production for June will now be 7.492 million bpd. West Texas Intermediate, the U.S. benchmark, traded 53 cents, or 2.1%, higher at $25.27 per barrel. Earlier in the session it traded as high as $25.58, and as low as $23.67. International benchmark Brent crude fell 15 cents to trade at $30.80 per barrel. Saudi Arabia also said that it would scale back May production "in consent with its customers." "The Kingdom aims through this additional cut to encourage OPEC+ participants, as well as other producing countries, to comply with the production cuts they have committed to, and to provide additional voluntary cuts, in an effort to support the stability of global oil markets," a statement from the Saudi press agency said. Oil is coming off its second straight positive week as investors have cheered signs that demand recovery is underway amid ongoing production cuts. WTI jumped 25% last week in one of its best weeks in history, while Brent rose 17%. Still, prices are well below their highs and the path to recovery is far from certain. "Despite the production curtailments that commenced this month, traders start to realize that the size of the supply-demand imbalance leaves little room for optimism," said Bjornar Tonhaugen, head of oil markets at Rystad Energy. "Storages in the US continue to fill up with crude and we are coming closer to tank tops by the day."
Saudi Arabia's oil production cuts show it is back in 'whatever it takes' mode, strategist says - Voluntary production cuts by OPEC members show that oil producing countries are doing what they can to stabilize the market during the ongoing coronavirus outbreak, one strategist told CNBC this week. Saudi Arabia on Monday said it will reduce output by an additional 1 million barrels per day from June 1, in a bid to support oil prices. Following the kingdom's announcement, the UAE and Kuwait also announced supply cuts. That's on top of an agreement between OPEC and non-OPEC allies, sometimes referred to as OPEC+, to lower production by 9.7 million bpd from May 1. "The OPEC heavyweights are sort of lining up to try to do what they can to stabilize this market," said Helima Croft, global head of commodity strategy at RBC Capital Markets. "We're already starting to see a pick up in demand as global lockdown conditions ease, people start driving again," she told CNBC's "Capital Connection" on Tuesday. "So, essentially what they're doing is acting as an accelerator in terms of getting the market rebalanced." However, while there are "green shoots," the outlook is unclear as the pandemic continues. "If we were to get a second wave in the crisis, if we were to get lockdown restrictions re-implemented, that could really change the trajectory of an oil price recovery," said Croft. "We really have to wait and see what is going to happen with this virus before we can basically say we're in the clear in terms of being on a sustainable path to recovery." More than 4.18 million people have contracted Covid-19 worldwide, and at least 286,336 people have died from the virus, according to data compiled by Johns Hopkins University.
Oil settles higher on hopes supply cuts, reopening economies will drain crude glut - Oil futures finished higher Tuesday, with U.S. prices at a five-week high on expectations that falling production levels and a gradual revival in demand from a COVID-19 pandemic-related drop, will ease a global glut of crude that has slammed prices in 2020. “Oil is back in rebound mode as the market is getting assurances that massive production cuts are coming,” said Phil Flynn, senior market analyst at The Price Futures Group. Saudi Arabia has promised to cut an additional 1 million barrels per day in June, in addition to its share of reductions under the output-cut agreement between the Organization of the Petroleum Exporting Countries and its allies, including Russia. Reuters reported Tuesday that OPEC+ wants to continue their existing oil production cuts beyond June, citing four OPEC+ sources. The agreement between the group of producers, known as OPEC+, called for output reductions of 9.7 million barrels per day from May 1 through June, with the group gradually reducing the size of the cuts after that, through April 2022. West Texas Intermediate crude for June delivery rose $1.64, or 6.8%, to settle at $25.78 a barrel on the New York Mercantile Exchange. That was the highest finish for a front-month contract since April 6, according to Dow Jones Market Data. July Brent crude added 35 cents, or 1.2%, t0 $29.98 a barrel on ICE Futures Europe. Saudi oil production for June, with the OPEC+ output-cut agreement and the voluntary cuts, will total 7.492 million barrels per day, the Saudi Press Agency reported Monday. Kuwait and the United Arab Emirates said Monday that they would offer support for the Saudi move by reducing production by 80,000 barrels and 100,000 barrels per day, respectively, in June. “Now comes word that Russia is making progress on reductions,” said Flynn, in a daily note. As part of the OPEC+ agreement, Russia reduced its oil and gas condensate production to 9.45 million barrels a day on May 1-11, from an average 11.25 million barrels per day in April, Reuters reported Tuesday, citing sources familiar with the data.
WTI Holds Big Gains Despite Bigger-Than-Expected Crude Build - Oil prices rallied (despite equity weakness) to their highest since early April today with WTI tagging a $26 handle after the Energy Information Administration revised down its 2020 and 2021 crude output forecasts in its monthly Short-Term Energy Outlook.“Production is indeed dropping and it might stay down for longer than people thought,” Bart Melek, head of commodity strategy at Toronto Dominion Bank said. "U.S. crude oil production has not declined for two years in a row since the 17-year period of declines beginning in 1992 and running through 2008," the agency said in its report."Typically, price changes affect production after about a six-month lag. However, current market conditions will likely reduce this lag as many producers have already announced plans to reduce capital spending and drilling levels."But the huge global glut remains and algos 'eyes' will be glue to API's data tonight... API:
- Crude +7.6mm (+4.3mm exp)
- Cushing -2.216mm (-1.00mm exp)
- Gasoline -1.911mm
- Distillates +4.712mm
This is the 16th weekly crude build in a row...but Cushing saw its first draw in 10 weeks...
Oil moves between gains and losses, caught between demand loss and supply cuts - Oil prices moved lower on Wednesday in choppy trading as demand concerns exacerbated by a possible second wave of coronavirus infections as countries ease lockdowns outweighed a possible extension of supply cuts by OPEC+. West Texas Intermediate crude fell 32 cents, or 1.2%, to trade at $25.46 per barrel, while Brent crude, the international benchmark, was unchanged at $29.98. "Fears are running rife that easing lockdown measures will trigger a second wave of coronavirus infections," said Stephen Brennoc at oil brokerage PVM. U.S. infectious disease expert Anthony Fauci on Tuesday told Congress that easing coronavirus lockdowns could set off new outbreaks of the COVID-19 disease that has killed 80,000 Americans and badly damaged the world's biggest economy and oil consumer. New outbreaks have been reported in South Korea and China, where the health crisis started before spreading across the globe, prompting governments to lock down billions of people, devastating economies and demand for oil. The U.S. Energy Information Administration (EIA) now expects world oil demand to fall by 8.1 million barrels per day (bpd) this year to 92.6 million bpd, compared with a previous forecast for a drop of 5.2 million bpd. The agency also expects U.S. output to fall by 540,000 bpd, against a previous forecast of 470,000 bpd. It expects global output of 11.7 million bpd this year and 10.9 million bpd in 2021. The Organization of the Petroleum Exporting Countries also slashed its world oil demand forecast and now expects it to contract by 9.07 million bpd this year, it said in a monthly report. Last month, OPEC expected a contraction of 6.85 million bpd. On the supply side, OPEC+ is looking to maintain existing cuts beyond June, when it meets next in Vienna, sources told Reuters. OPEC and other producers including Russia - a group known as OPEC+ - agreed to cut output by 9.7 million bpd in May and June and to scale back cuts to 7.7 million bpd for the rest of the year. Saudi Arabia's cabinet has urged OPEC+ countries to reduce output further to restore balance in global crude markets, the country's state news agency reported early on Wednesday. Riyadh said it would add to planned cuts by reducing production by a further 1 million bpd next month, bringing output down to 7.5 million bpd.. In the United States, crude oil inventories rose by 7.6 million barrels last week to 526.2 million barrels, against analyst expectations for an increase of 4.1 million barrels, the American Petroleum Institute (API) said on Tuesday. Still, stocks of crude at the Cushing delivery hub in Oklahoma fell by 2.3 million barrels, API said. If confirmed by official data, that would be the first drawdown since February, ING Economics said.
WTI Spikes After Surprise Crude Draw, Production Plunge - Oil prices have roundtripped from last night's API print, as overnight gains were erased after OPEC presented a bleaker assessment of global oil markets for the second quarter as the COVID-19 crisis continues to drain demand.Notably, just as OPEC members begin to cut production, the cartel cut estimates for the amount of crude it will need to supply over the three-month period by just under 3 million barrels a day, or about 15%, in a report published this morning.“On the demand side there’s probably a view that the worst may be behind us, in terms of the peak damage point. If we do see a second wave, that would hurt demand and hurt pricing,” said Commonwealth Bank’s Dhar.And so once again we look to inventory data for clues with all eyes on Cushing today given some expectation that we’re about to see the beginning of the end of the storage capacity issue. DOE:
- Crude -745k (+4.3mm exp)
- Cushing -3.002mm (-1.00mm exp)
- Gasoline -3.513mm
- Distillates +3.511mm
The 15-week streak of crude inventory builds is over with a 745k barrel draw this week and fears over Cushing storage maxing out seem assuaged... Nationwide crude stocks fell for the first time since January, while Cushing stocks declined for the first time since February and its largest decline since that month. Bloomberg Intelligence Energy Analyst Fernando Valle notes that "falling tanker rates show that pressure on storage has eased in May as OPEC+ cuts output. An initial recovery in gasoline demand as several U.S. states emerge from lockdown could drive another draw on inventories, but exports are likely to remain subdued. Diesel is in an increasingly delicate situation, as industrial and trade activity slows at the same time as refiners shift volume from jet fuel. Margin recovery is shallow, but positive. Questions remain on how long-lived it will be, as coronavirus cases grow in the U.S. South."US crude production has plummeted quickly - though not as quickly as rig counts have collapsed - down 300k b/d...
Oil prices post a loss even as weekly U.S. crude supplies and stocks at the Cushing storage hub decline - Oil prices settled with a loss on Wednesday, failing to find support even after U.S. government data showed an unexpected weekly decline in domestic crude supplies, along with a fall in stocks at a key storage hub in Cushing, Okla. “As we have seen a good amount of states opening back up, demand for gasoline should easily continue to get better—especially since we are coming from such a demand destruction here in the U.S.” . “However, air travel worldwide…is a long way from coming back.”Zahir said he wouldn’t be surprised to see COVID-19 cases increase in the weeks to come because it takes a couple of weeks for the virus to present itself. “We feel that DNA in the consumer has been badly damaged” and the economy is likely to recover “very slowly” with the amount of jobs lost.Oil can “definitely go higher a few dollars in the next few days, but we feel it will be short lived,” he said. “With space becoming available in Cushing, and with prices going higher” recent pledges by certain countries to cut production may not see full compliance.West Texas Intermediate crude for June delivery on the New York Mercantile Exchange fell by 49 cents, or 1.9%, to settle at $25.29 a barrel. It had briefly turned higher immediately after the EIA supply data. The global benchmark, July Brent fell 79 cents, or 2.6%, at $29.19 a barrel on ICE Futures Europe.The Energy Information Administration reported Wednesday that U.S. crude inventories fell by 700,000 barrels for the week ended May 8. That marked the first weekly decline in 16 weeks and defied a forecast by analysts polled by S&P Global Platts for an average increase of 4.8 million barrels. The American Petroleum Institute on Tuesday reported a climb of 7.6 million barrels. The EIA report was “bullish, but the mood is bearish,” Phil Flynn, senior market analyst at The Price Futures Group, told MarketWatch. “The risk-off environment in the stock market is having traders overlook the green shoots” in the report.
Oil jumps 9% on dip in U.S. crude stockpiles, IEA data - Oil prices surged on Thursday after the International Energy Agency forecast lower global stockpiles in the second half of 2020, even as worries remain over a second surge in coronavirus infections in coming months. Crude prices have ticked up in the last two weeks as some countries relaxed coronavirus restrictions and lockdowns to allow factories and shops to reopen. West Texas Intermediate crude futures surged 8.98%, or $2.27, to settle at $27.56 per barrel, while Brent crude futures rose $1.94, or 6.65%, to settle at $31.13 per barrel. The market rebounded from Wednesday's losses built on a glum forecast for the economy from U.S. Federal Reserve Chairman Jerome Powell, who warned of an "extended period" of weak economic growth. That offset an unexpected drop in U.S. stockpiles. Initial claims for state unemployment benefits totaled a seasonally adjusted 2.98 million for the week ended May 9, the U.S. Labor Department said on Thursday. While that was down from 3.18 million in the prior week and marked the sixth straight weekly drop, claims remain astoundingly high. "Gasoline demand correlates pretty well with the employment level, and it's hard to see gasoline demand come back much more than it already has," said John Kilduff, partner at Again Capital LLC in New York. U.S. crude inventories fell for the first time in 15 weeks, the Energy Information Administration said on Wednesday, with a fall in U.S. crude stockpiles of 745,000 barrels to 531.5 million barrels in the week to May 8. On Thursday, the IEA again forecast a record drop in demand in 2020, although it trimmed its estimate for the fall, citing measures to ease lockdowns. As demand increases, the IEA expects crude stockpiles to shrink by about 5.5 million barrels per day in the second half. "While these supply and demand dynamics are certainly capable of boosting prices near term, a potential record level of global crude supply will remain as a force to be reckoned with,"
Oil extends gains amid signs of China demand pickup, global supply overhang fading -Oil prices rose on Friday, extending day-earlier gains, as data showed demand for crude picking up in China after the easing of curbs to stem the coronavirus outbreak, boosting hopes that the global supply overhang may start to fade. Brent crude was up 63 cents, or 2% at $31.76 per barrel, after rising nearly 7% on Thursday. The global benchmark is heading for a 1.8% gain on the week after rising for the previous two weeks. West Texas Intermediate was up $1.23, or 4.4%, to trade at $28.78 per barrel, having jumped 9% in the previous session. WTI is heading for a third weekly increase, up more than 12%. Amid supply cuts by the Organization of the Petroleum Exporting Countries (OPEC) and other major producers, bright spots are also emerging on the demand side. Data released on Friday showed China's daily crude oil use rebounded in April as refineries ramped up operations. Still the market mood remains far from euphoric, with the coronavirus pandemic far from over and new clusters emerging in some countries where lockdowns have been eased. "The fundamentals in the market are clearly improving," ING Research analysts said in a note. "But we still believe that in the near term, the upside is limited given that we are still in a surplus environment ... There is plenty of inventory for the market to digest." There is optimism that stockpiles may be on the wane. The International Energy Agency said it expects crude inventories to fall by about 5.5 million barrels per day (bpd) in the second half of this year. Meanwhile U.S. crude inventories fell for the first time in 15 weeks, the Energy Information Administration said on Wednesday. Output cuts will boost the trend towards lower inventories, but U.S. crude is unlikely to see strong gains. "WTI crude will struggle to break above the $30 level until both the economic outlook improves for the U.S. and some of the downside risks ease," said Edward Moya, senior market analyst at OANDA. On the production side, OPEC and associated producers — collectively known as OPEC+ — had already agreed to cut output by a record of nearly 10 million bpd before Saudi Arabia this week extended its planned reductions for June, pledging to lower supply by nearly 5 million bpd.
The Relentless Oil Price Rally | OilPrice.com Oil prices are continuously rising despite the uncertainty surrounding COVID-19, with WTI nearing a two-month high on Friday morning.Oil prices appear to be rising relentlessly, with WTI bouncing above $28 per barrel, nearly at a two-month high. Market sentiment has been gaining steam as supply shut-ins mount and demand begins to come back. Still, the risk of another wave of coronavirus infections presents a major risk to the rally.“The ministers want to keep the same oil production cuts now which are about 10 million bpd, after June. They don’t want to reduce the size of the cuts. This is the basic scenario that’s being discussed now,” one OPEC+ source told Reuters. Oil time spreads have seen a narrowing contango, a sign of tightening in the oil market. “We believe stocks will be reduced gradually over the next 12 months or so,” said Rystad Energy head of oil markets Bjornar Tonhaugen. “Brent stabilizing above $30 gives the market confidence that frightening days of negative prices and record daily declines are behind us.” The flotilla of Saudi supertankers heading to U.S. ports have been delayed because there has been a shortage of the smaller ships used to lighten the load near shore. Due to sharp cuts in oil production, the pace of inventory builds has slowed dramatically, easing fears of an acute shortage in storage capacity. Iraq cut 650,000 bpd from its massive southern oil fields in order to comply with the OPEC+ cuts. The reductions have been split between state-owned companies and the private international companies. Exxon CEO Darren Woods is underscrutiny after Legal & General Investment Management, which oversees $1.5 trillion in assets, said it would vote against Woods as CEO and Chairman at the company’s upcoming shareholder meeting. The investment group cited Exxon’s “lack of strategic ambition around climate change,” while its European competitors “step up and reaffirm their sustainability ambitions.” Wood Mackenzie outlined several scenarios in a new report, all of which paint a pessimistic outlook for oil demand. The firm said it could take years for demand to recover, but ultimately, demand will probably peak within the next decade. Federal Reserve Chairman Jerome Powell warned of an “extended period” of economic damage. St. Louis Fed Chair James Bullard warned job losses could be permanent and businesses could fail “on a grand scale.” The World Health Organization warned that the world may live with COVID-19 indefinitely. “It is important to put this on the table: this virus may become just another endemic virus in our communities, and this virus may never go away,” WHO emergencies expert Mike Ryan told an online briefing. Diamond Offshore took advantage of stimulus money passed by Congress, getting a $9.7 million tax refund. Then it asked a bankruptcy judge to reward top executives the same amount. Oil companies are receiving hundreds of millions of dollars in stimulus money. “This is a stealth bailout for the oil and gas industry,” Jesse Coleman, a researcher with Documented, told Bloomberg.
Oil prices jump as demand shows signs of picking up - (Reuters) - U.S. crude prices jumped 7% on Friday to their highest since March, on strengthening fuel demand as countries around the world eased travel restrictions they had imposed to curb the spread of the coronavirus. U.S. crude gained 19.7% in the week and Brent crude rose 5.2% after a week of bullish news. Both contracts gained for the third consecutive week. West Texas Intermediate (WTI) oil settled up $1.87, or 6.8% at $29.43 a barrel, just off the session peak of $29.92, its highest since mid-March. WTI soared 9% in the previous session. Brent crude settled up $1.37, or 4.4% a barrel at $32.50. Brent rose nearly 7% on Thursday. The second-month contract for U.S. crude traded at a discount to the first month for the first time since late February, implying market tightness, said Bob Yawger, director of energy futures at Mizuho in New York. “It is no accident the spread switched after EIA crude oil storage, and storage at the NYMEX delivery site at Cushing, both posted up their first storage draws in weeks in Wednesday’s storage report,” he said. The Organization of the Petroleum Exporting Countries and other major producers have cut supplies to reduce a glut, and now there also are signs of improving demand. Data showed China’s daily crude oil use rebounded in April as refineries ramped up operations. Still, the market remained cautious with the coronavirus pandemic far from over and new clusters of infection emerging in some countries where lockdowns have eased. “Oil prices have been up significantly since yesterday thanks to a better assessment of the situation by the International Energy Agency (IEA),” Commerzbank said in a note. The IEA expects global crude inventories to fall by about 5.5 million barrels per day (bpd) in the second half. It also expects oil demand this year to fall by 8.6 million bpd, smaller by 690,000 bpd than the decline it forecast last month. It expects non-OPEC supply to fall by 3.2 million bpd. Barclays raised its forecasts for Brent and WTI by $5-$6 a barrel for 2020 and by $16 a barrel for 2021. It now sees Brent prices averaging $37 a barrel and WTI at $33 this year. For 2021, the bank expects Brent to average $53 a barrel while WTI averages $50.
U.S. Oil Just Shy of $30, Chugging Along on China Data - President Donald Trump might very be disappointed with China these days, but it was Chinese data on Friday that helped accelerate U.S. crude oil’s run toward $30 per barrel. West Texas Intermediate, the New York-traded benchmark for U.S. crude, settled up $1.87, or 6.8%, at $29.43 per barrel after data showed China's industrial production rose 3.9% in April from a year ago, improving from a 1.1% fall in March. Brent, the London-traded global benchmark for oil, rose $1.37, or 4.4%, to settle at $32.50. WTI has been on a tear since hitting a bottom of $12.34 on Aug 28, rallying almost 140% in just over two weeks. The U.S. crude benchmark remains down 50% on the year. But Friday’s two-month high of $29.91 in WTI brought its discount versus Brent, typically at $5 per barrel, to under $3 at one point, powerfully altering the dynamics between the two benchmarks. For the week, WTI gained 19%, extending last week’s 25% jump and the previous week’s 17% rise. Brent saw a relatively modest climb of 5% on the week. Its gains over the past two weeks were virtually a reverse of WTI’s — 17% last week and 23% the previous week. Much of the boom in U.S. crude of late has been due to cratering domestic production, as the coronavirus pandemic shut down wells and oil rigs across the United States at a faster rate than elsewhere in the world. Rising gasoline production has also helped as most of the 50 U.S. states have reopened from lockdowns imposed over the Covid-19. Rising gasoline consumption has also helped as most of the 50 U.S. states have reopened from lockdowns imposed over the Covid-19. But Friday’s run toward $30 WTI — an important psychological mark for oil bulls —- came on the back of China’s resurgent industrial production data underscoring a recovery in factory activity in the world’s largest oil importing country. It also comes a day after President Donald Trump said he was very disappointed with China's failure to contain the outbreak of the virus, and that he might even cut ties with the world's second largest economy. “WTI crude neared a two-month high as China’s industrial output rose for the first time since the coronavirus pandemic, fueling hope that crude demand will soon improve in Europe and then the U.S.” said Ed Moya, analyst at New York’s OANDA. “China remains the template for the economic recovery for the rest of the world and (it) gave energy traders some hope that demand will begin to recover over the coming weeks.”
Oil Futures Settle Sharply Higher For The Day, Gains 19% In Week - Crude oil futures ended sharply higher on Friday, extending recent gains, amid hopes on some improvement in energy demand following reopening of businesses in several parts across the globe, and on hopes the output cuts from major producers will support prices. West Texas Intermediate Crude oil futures for June ended up $1.87, or about 6.8%, at $29.43 a barrel. Brent Crude futures were gaining about $1.1 or about 3.6% at $32.23 a barrel. On Thursday, WTI Crude oil futures for June ended up $2.27, or 9%, at $27.56 a barrel. WTI Crude oil futures gained about 19% in the week. According to Baker Hughes, the number of active U.S. rigs drilling for oil dropped by 34 to 258 this week, falling for a ninth straight week. The total active U.S. rig count also fell, dropping by 35 to 339, according to the report from Baker Hughes. Data showing a notable rebound in China's daily crude oil use in April amid increased activity supported oil's uptick. According to International Energy Agency, (IEA), crude inventories are expected to fall by about 5.5 million barrels per day (bpd) in the second half this year. The IEA estimates that global oil supply is set to fall by a spectacular 12 mb/d to a nine-year low of 88 mb/d in May, as the OPEC+ agreement takes effect and global production declines.
Saudi Arabia Running Out Of Money: Riyadh To Slash Spending By $27 Billion, Suspend Cost Of Living Allowance - Last weekend we quoted Finance Minister Mohammed Al-Jadaan, who warned that the world's biggest oil exporter hasn’t witnessed "a crisis of this severity" in decades, adding that government spending will have to be cut "very deeply", something we touched on previously. We didn't have long to wait, because early on Monday, the Saudi government - which appears to be running out of money fast - ordered government spending cuts including suspending the cost of living allowance amid broad austerity measures for about $26.6 billion and a tripling of the value-added tax as part of measures aimed to shore up state finances, which have been battered by low oil prices and the coronavirus."Cost of living allowance will be suspended as of June first, and the value added tax will be increased to 15% from 5% as of July first," said the Saudi finance minister according to the state news agency, suggesting Saudi Arabia is on the verge of a full-blown fiscal crisis.Other measures includes canceling or delaying some operational and capital expenditures for a number of government agencies and reducing the credits planned for a number of state initiatives, including the Vision 2030 project, just as we predicted."The covid-19 challenges have led to a decline in government revenues, and pressure on public finances to levels that are difficult to deal with later without harming the kingdom’s macroeconomics and public finances in the medium and long term,” Al-Jadaan said. “Therefore more spending cuts must be achieved, and measures to support the stability of non-oil revenues."Already under a strict curfew to contain the spread of the coronavirus pandemic, the world’s largest oil exporter has been affected by the oil price rout and global crude production cuts to help balance the market. The price of Brent crude crashed by more than 50% in March, contributing to a record $27 billion monthly drop in the Saudi central bank’s net foreign assets. Adding insult to injury, last week we warned that the Kingdom may soon be dealing with a funding crisis as well: the collapse in crude prices and the government’s drop in foreign reserves, which plunged by a record $27BN in March... ... is putting more pressure on the Saudi riyal. For now, however, prices for 12-month dollar-riyal forward contracts are well short of their all-time high reached in 2016.
Oil Price War Puts Entire Kingdom Of Saudi Arabia At Risk - At no time since Ibn Saud first consolidated his Arabian conquests into the Kingdom of Saudi Arabia in 1932 has the ruling Saud dynasty faced such an existential threat to its continued rule over the country. It is true that Saudi Arabia has been able to gain some temporary advantage in key Asian export markets, as its shipments to China more than doubled in April to 2.2 million barrels a day (bpd) and those to India, at 1.1 million bpd, were also the highest in at least three years. This, though, as much as any other factor that might endure, was a product of Saudi slashing its official selling prices (OSPs) for April crude sales to some of the lowest levels in decades, undercutting its rivals, and exactly the same happened again for May crude sales. Even this very slight victory, though, has already been jeopardised by an indication that the scale of the trouble into which the House of Saud has placed Saudi Arabia is truly monumental. Just last week saw massive economic pressure force the Saudis into increasing the June delivery price for its Arab light crude oil to Asia by US$1.40 per barrel from May, albeit at a discount of US$5.90 to the Oman/Dubai benchmark average. Market expectations were that Saudi would continue to keep OSPs low to hold onto market gains. Saudi Arabia did this because its finances are in an even worse state now than they were at the end of the Kingdom’s previous attempt to destroy the U.S. shale industry that ran disastrously from 2014 to 2016. Back then, Saudi had a much greater chance of success in destroying the U.S. shale industry than it did this year, for a wide variety of reasons, but even then the effort nearly destroyed the Saudi economy forever. Back then Saudi had record-high foreign assets reserves of US$737 billion in August 2014, allowing it real room for manoeuvre in sustaining its SAR/US$-currency peg and covering the huge budget deficits that would be caused from the oil price fall caused by overproduction. Despite this relatively positive backdrop to Saudi’s 2014-2016 oil price war against U.S. shale, OPEC member states lost a collective US$450 billion in oil revenues from the lower price environment, according to the IEA. Saudi Arabia itself moved from a budget surplus to a then-record high deficit in 2015 of US$98 billion and spent at least US$250 billion of its foreign exchange reserves over that period that even senior Saudis have said are lost forever. So bad was Saudi Arabia’s economic and political situation back in 2016 that the country’s deputy economic minister, Mohamed Al Tuwaijri, stated unequivocally (and unprecedentedly for a senior Saudi) in October 2016 that: “If we [Saudi Arabia] don’t take any reform measures, and if the global economy stays the same, then we’re doomed to bankruptcy in three to four years.” That is to say, that if Saudi kept overproducing to push oil prices down – just as it did this year, yet again - then it would be bankrupt within three to four years.
Jordan's King Warns '”Massive Conflict” Coming If Israel Moves To Annex West Bank - With Washington's backing, Israel is planning to move forward on controversial plans to annex a broad swath of the West Bank, particularly the Jordan Valley, as early as this summer. PM Netanyahu last month issued a likely time table of "within two months".Arab nations, especially in the gulf, have remained uncharacteristically mum about the whole thing as they focus on countering Iran (which has, it should be noted, actually brought Saudi Arabia into a quiet 'covert' intelligence sharing relationship with Israel over the past couple years).But Jordan on Friday finally went on the offensive, with King Abdullah telling the German magazine Der Spiegel that Israeli annexation of parts of the West Bank “will lead to a massive conflict with Jordan”. The 'warning' was posted to the official website of the king's Royal Hashemite Court on Friday:Asked about the impact of Israel potentially moving forward with the annexation of parts of the West Bank, the King said it could lead to a massive conflict with Jordan.“I don't want to make threats and create an atmosphere of loggerheads, but we are considering all options. We agree with many countries in Europe and the international community that the law of strength should not apply in the Middle East,” His Majesty added.He further reaffirmed Jordan’s position that “the two-state solution is the only way for us to be able to move forward.” He at the same time urged the region to focus on collective efforts at fighting coronavirus instead of clashing with each other, as he said will happen if Israel initiates its provocative and 'illegal' expansionist plans.Abdullah, who maintains a close relationship with the United States and has long opened his country to CIA and US military presence especially during the early years of regime change efforts in Syria, also warned that "chaos and extremism in the region" would be unleashed if the Palestinian Authority collapsed."Leaders who advocate a one-state solution do not understand what that would mean. What would happen if the Palestinian National Authority collapsed? There would be more chaos and extremism in the region," he said.
Mysterious 2,819% Stock Rally Has Traders Scratching Their Heads - An Abu Dhabi-based investment holding company is leaving traders and investors scratching their heads after a 2,819% surge in its stock in the past 12 months with very low trading volumes. International Holdings Co. PJSC, which derived most of its revenue in 2019 from fish farming in the United Arab Emirates, has reached a market value of $14 billion, up from about $133 million a year ago. The steep rally in its shares hasn’t been dented by this year’s global equity market meltdown sparked by the coronavirus pandemic, or the collapse in oil prices which roiled Middle-Eastern markets. The company’s shares are up 351% in 2020. The uninterrupted surge has made it the best performing stock worldwide in the past 12 months among companies worth $1 billion or more, and IHC is now the fifth-biggest listed group in the U.A.E. by market value, after Emirates Telecom Group Co., First Abu Dhabi Bank PJSC, Emirates NBD PJSC and DP World Plc.